Systems and methods for producing steam using solar radiation

ABSTRACT

Methods and systems for generating steam using solar energy are provided here. The methods and systems can be used to generate steam of a desired quality, e.g. about 70%, or superheated steam. Some methods for producing steam of a desired quality comprise flowing water into an inlet of receiver in a linear Fresnel reflector system, wherein the receiver comprises multiple parallel tubes t i  connected in parallel, and i=1,k, and irradiating each tube t i  along its respective length L i  with solar radiation so that solar radiation absorbed at each tube generates thermal input along its length and so that water begins to boil in at least one of the tubes at a point λ i  along its length. The methods comprise using one or more temperatures T i  in an economizer region of a tube t i  or one or more changes in length of the tubes as input to a controller that controls mass flow of water into each of the multiple tubes, thereby controlling quality of steam exiting the receiver.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority from U.S. provisional patent application entitled “Systems and Methods for Producing Steam Using Solar Radiation”, application Ser. No. 61/216,253, inventors William M. Conlon, Peter M. Tanner, Milton Venetos, and Robert J. Hanson, filed on May 15, 2009, and U.S. provisional patent application entitled “Systems and Methods for Producing Steam Using Solar Radiation”, application Ser. No. 61/216,878, inventors William M. Conlon, Peter M. Tanner, Milton Venetos, and Robert J. Hanson, filed on May 22, 2009, each of which is hereby incorporated by reference in its entirety for all purposes as if put forth in full below.

FIELD

This application relates to methods, systems and apparatus for producing steam, in particular for producing steam using solar radiation. The methods, systems and apparatus include control schemes to control output steam quality, especially during variations in or interruptions to thermal input (e.g. thermal input generated by solar radiation).

BACKGROUND

Solar thermal power plants generate electricity by using solar radiation to heat a working fluid to power a turbine, such as a steam turbine, that is coupled to an electrical generator. Various solar energy collector systems for generating steam have been developed. Solar energy collector systems may comprise, for example, parabolic trough systems, central receiver systems with 2-axis heliostats, or Linear Fresnel Reflector (LFR) systems.

In some cases, it may be desired to use solar-generated steam directly, e.g. as process steam that can be used for a variety of applications, including process heat, enhanced oil recovery, food processing, agricultural processing, refrigeration, pulp and paper processing. In many applications for steam, e.g. oil field steam injection for enhanced oil recovery, it is important to know steam mass flow rate and steam quality. Examples of control methods that can be used in solar thermal power plants are described in U.S. Patent Publication No. 20090101138, published Apr. 23, 2009 and U.S. Patent Publication No. 20080184789, published Aug. 7, 2008.

A need exists for improved methods, systems, and apparatus for producing steam with a determined mass flow rate and steam quality, especially in instances where there may be variability or interruptions in thermal input, such as there may be in the case where solar radiation is used to provide all or part of the thermal input to a steam generator.

SUMMARY

The invention in one instance provides a method of operating a steam boiler which utilizes solar energy to generate the steam. This method involves using information on a system variable that affects steam quality in a control strategy predictive of the steam quality to be output from the boiler to adjust the flow rate (e.g. mass flow rate) of water passing through a tube of the boiler to attain that steam quality.

In one instance, the amount of heat in water is assessed at a known location along the tube, and this information on amount of heat in water is used to adjust a flow control valve for water entering this tube or another tube to provide steam of the desired quality. Alternatively, a flow controlling orifice may be used alone or in conjunction with the flow control valve to control the amount of water entering this tube or another tube to provide steam of the desired quality. The flow controlling orifice may include a device that restricts flow (e.g. by having a reduced inner diameter) and/or modifies flow, e.g. to reduce turbulence, bubbles, rotational flow, or the like.

In another instance, the elongation of a tube is used to predict the quality of steam that will emerge from the solar boiler, and the flow rate of water into the boiler tube is adjusted to produce the desired quality of steam. Elongation may be measured in a region of the tube in which water is heated prior to generating steam.

In another instance, the elongation of a portion of a tube in a superheat region of the tube is used to calculate or represent the quality of superheated steam in the superheat region of the tube.

Flow rates may, for instance, deliberately differ through different tubes of a boiler or of a receiver to provide steam of a desired quality from each of the tubes. The control of flow-rates may be based on a change of length of an individual tube, or a deviation in change of length from an average or mean of the change in length of all tubes. The change in length of each tube of a multi-tube array or a multi-pass array having two or more absorber tubes may be the same, and water flow rate in tubes of the array may be controlled to provide the same tube elongation. As noted above, the elongation of fewer than all tubes may be used to control water flow rate in each tube and/or illumination of each of the tubes of the array.

In another instance, one or more characteristics indicative of total heat in steam and any condensate emerging from a tube of a solar boiler is used to predict the amount of heat in steam and any condensate that will be produced in a second boiler tube of the solar boiler. For instance, a receiver of a linear Fresnel reflector array may have multiple parallel boiler tubes in an array in the receiver, such as a planar array. The heat in steam emerging from a tube at or near the center of the array of tubes, which tends to be illuminated better than tubes at ends of the (e.g. planar) array of tubes, may be used to predict the heat that will emerge from other tubes of the array (such as the end tubes), and water flow rate and/or heat input to the other tubes may be adjusted by adjusting a water flow control valve and/or a flow controlling orifice for the tube and/or moving reflectors to illuminate end tubes more or less. The elongation of a tube in the portion of the tube in which steam is superheated may be one of the characteristics that indicates total heat in steam emerging from a tube.

The invention also provides steam boilers and control systems that are configured to operate as described above. In one instance, a solar boiler has an elongation measurement device in an economizer section of a tube. The elongation measurement device may be coupled to a control system that utilizes information representative of mass flow rate of water through the tube and elongation to assess the amount of heat contained in water entering the tube. The control system actuates a water flow control valve for the tube that opens and closes to regulate the flow rate of water through the tube based on a correlation of the tube elongation with heat in the combined steam and condensate, if any, emerging from the pipe. Alternatively, a flow controlling orifice may be used alone or in conjunction with the water flow control valve to regulate the flow rate of water through the tube based on a correlation of the tube elongation with heat in the combined steam and condensate, if any, emerging from the pipe.

In another instance, a solar boiler has a measurement instrument such as one or more pressure and/or temperature sensors that interacts with a control system to assess quality of steam at an end of a boiler tube of a multi-tube receiver or multi-pass receiver having two or more absorber tubes upon which solar energy is focused. The control system is configured to change a flow rate of water into a second tube of the multi-tube or multi-pass receiver, a position of one or more reflectors that illuminate the second tube of the receiver, or both as a result of deviation of quality of the steam from expected or target quality absent an upset such as a shadow or cloud passing across the reflectors of the solar boiler.

The control systems incorporated into a solar boiler and method as described above may be configured to accept inputs from one or more temperature, pressure, steam quality, flow rate, photodetector, reflector position, tube elongation, and other detectors or instruments that measure these values and control water flow rate and/or reflector position. The control system may incorporate a proportional controller, a proportional-integral (PI) controller, a proportional-derivative (PD) controller, a proportional-integral-derivative (PID) controller in analog or digital form, or another form of control or modification of one of these control schemes. The control system of any of the solar boilers disclosed herein may also have two or more cascaded controllers, where an output of one controller is an input to a second controller.

The method, apparatuses, and control systems as discussed herein may be reactive to an input such as change of length of receiver tube. For instance, the control system may contain look-up data representative of desired change in length of each tube of a receiver. The set-point may represent a steady-state operation for the particular receiver tube. The control system may compare the instrument input representative of the value of change in length with the set-point and adjust one or more of the water flow rate through the tube and reflector position to provide the desired change in length. An instrument input representative of e.g. steam quality may be used to adjust the set-point.

The above methods, apparatuses, and control systems may be used or configured to generate saturated steam. Alternatively, the methods, apparatuses, and control systems may be used or configured to generate superheated steam.

Tube elongation may be measured a number of ways. A reference point may be selected, such as a point at which the tube is secured to a support. Alternatively, a reference point may be provided at a movable position on a tube, and elongation may be measured from that reference point to another point on the tube.

An amount of heat lost from a tube or the apparatus overall may be used to refine the operation of an apparatus and control system as described herein. The heat lost may be modeled, measured, or calculated from measured values.

Data from a first tube of a multi-tube receiver, multi-pass receiver having two or more absorber tubes, or multi-tube solar boiler through which water and steam pass quickly relative to other tubes of the receiver or boiler can be used to adjust flow rate of water through a second tube, rate at which heat is input, or both. Thus, data obtained on e.g. steam quality emerging from the first tube can be used to adjust flow rate and/or heat input to affect steam quality in the second tube to compensate for any deviations from a desired steam quality encountered in steam from the first tube.

One benefit of this type of configuration and method is that data need only be obtained for some but not all of the tubes of the multi-tube solar boiler, multi-tube receiver, or multi-pass receiver having two or more absorber tubes in order to control steam quality emerging from each of the tubes of the receiver or boiler. This reduces the number of parts required to operate a system, making the system more reliable and less costly. Transit times of fluid through elongated tubes can be on the order of several minutes or even hours; utilizing data from those tubes exhibiting fastest transit times of fluid to control steam quality emerging from each of the tubes in the receiver can improve time response in a system employing a multi-tube receiver or multi-pass receiver with two or more absorber tubes, which can result in faster stabilization and faster response to transient changes in thermal input (e.g. due to clouds or shadows).

In another instance, the method and boiler are configured to provide a position of an initial boiling point from an input end of a solar boiler tube that is the same for some or all tubes in a multi-pass receiver having two or more absorber tubes or a multi-tube receiver or some or all tubes in the solar boiler.

In another instance, the method and boiler are configured to provide a position of where superheat begins from an input end of a solar boiler tube that is the same for some or all tubes in a multi-pass receiver having two or more absorber tubes or a multi-tube receiver or for some or all tubes in the solar boiler.

In some instances, the quality of steam output from the solar boiler and/or individual tubes of the solar boiler is no more than 70% (0.70). In other instances, the quality of steam is greater than 1.

Pressure of the steam output from the system may be controlled separately by a controller that senses steam pressure at or from a steam drum or other steam accumulator and adjusts a valve at the drum or in a steam line to or from the drum to increase or decrease pressure. Alternatively, a flow controlling orifice may be used alone or in conjunction with the valve to adjust the pressure.

The systems and methods above may be configured in a linear Fresnel reflector array or in an array of trough collectors, as desired.

Also included herein are various methods of start-up for a solar boiler. The invention is not limited to the apparatuses, methods, and control systems described in this summary but is additionally described in various portions of the text, figures, and claims below.

Solar input along a length of tube may or may not be uniform. For instance, solar input may be uniform on a cloudless day, where one or more reflectors focuses sunlight along a length of the tube. Solar input may not be uniform where, for instance, clouds block light from reaching portions of the length of a tube but not the entire length of tube that is illuminated on a cloudless day. Solar input may not be uniform where, for instance, light from various structures of a solar array block light from reaching portions of the length of a tube but not the entire length of the tube.

Thus, methods and systems for generating steam using solar energy are provided here. The methods and systems can be used to generate steam of a desired quality, e.g. about 70%, or superheated steam. The steam generated by the methods and systems described herein can be used directly, e.g. as process steam for applications such as food processing, enhanced oil recovery, agricultural processing, pulp and paper processing, industrial processes, heating and cooling, and the like, or to power a turbine to generate electrical power.

Variations of the methods and systems for controlling output steam quality described herein are applicable to solar thermal systems employing a single absorber tube, those employing multiple absorber tubes, which may be connected in parallel, and those employing multi-pass absorber tubes. The methods and systems allow improved production of a desired steam quality or superheated steam, where steam quality and steam output can be controlled within a desired range even in the event of systematic or transient variations in insolation that results in systematic or transient variations in thermal input to the absorber tubes.

Variations of the methods and systems for controlling output steam quality described herein are applicable to solar thermal systems employing a single absorber tube, those employing multiple parallel-connected absorber tubes, and those employing multi-pass absorber tubes. The methods and systems allow improved production of a desired steam quality or superheated steam, where steam quality and steam output can be controlled within a desired range even in the event of systematic or transient variations in insolation that results in systematic or transient variations in thermal input to the absorber tubes. In certain variations, the methods and systems may allow for decreased requirements for water inventory, and/or reduced start up losses.

Some methods for producing steam of a desired quality comprise flowing water through an inlet to enter an elongated tube under pressure, and irradiating the tube along its length with solar radiation so that solar radiation absorbed by the tube generates thermal input along its length, water begins to boil at a boundary along the tube, and steam exits the tube. The methods further comprise using a change in tube length as input to a controller that controls mass flow of water into the tube inlet, thereby controlling quality of steam exiting the tube. For instance, the tube can be mounted such that it is relatively free to expand at the inlet. In some variations, the tube is anchored at a position P between the tube inlet and a tube outlet, where position P extends further from the inlet than the boiling boundary, and the change in tube length between position P and the inlet can be used to control mass flow of water into that tube.

Some methods for producing steam of a desired quality comprise flowing water into an inlet of receiver in a linear Fresnel reflector system, wherein the receiver comprises multiple parallel tubes t_(i) connected in parallel, and i=1, . . . , k, and irradiating each tube t_(i) along it respective length L_(i) with solar radiation so that solar radiation absorbed at each tube generates thermal input along its length and so that water begins to boil in at least one of the tubes at a point λ_(i) along its length. The methods comprising using one or more temperature measurements T_(i) in an economizer region of a tube t_(i) as input to a controller that controls mass flow of water into each of the multiple tubes, thereby controlling quality of steam exiting the receiver.

Some methods for producing steam of a desired quality comprise flowing water into an inlet to enter an elongated tube of length L under pressure, irradiating the tube along its length L so that steam exits the tube, and controlling water flow into the tube with a control system that utilizes a temperature measurement in the economizer region of the tube as a control variable. A set point for the control system depends from the position of the temperature measurement relative to the inlet, tube length L, and a desired output steam quality.

Some methods for producing steam of a desired quality comprise flowing water through an inlet to enter an elongated tube under pressure, the tube having a length L and a transverse dimension W that is orthogonal to L and rotating a reflector about a single axis parallel to the tube to direct solar radiation to irradiate the tube along its length L to provide thermal input to the tube along its length L and so that steam exits the tube. The methods comprise i) controlling mass flow of water into the tube inlet; and ii) adjusting a thermal input to the tube by rotating a position of the reflector to control quality of steam that exits the tube.

Some methods for producing steam of a desired quality comprise flowing water through an inlet to enter an elongated elevated receiver comprising multiple parallel tubes under pressure or one or more multi-pass tubes under pressure, the receiver having a length L and a transverse dimension W that is orthogonal to L, and rotating one or more linear Fresnel reflectors about an axis parallel to the receiver in a field comprising multiple rows of linear Fresnel reflectors to direct solar radiation to irradiate the tubes along length L to provide thermal input to the tubes along length L and so that steam exits the receiver. The methods further comprise adjusting a thermal input to the multiple parallel tubes, multiple segments of a multi-pass tube, or multiple multi-pass tubes along the transverse dimension W of the receiver by rotating one or more reflector rows about an axis that is parallel to the elongated receiver, and controlling steam quality exiting the receiver by i) controlling water flow into the multiple parallel tubes, single multi-pass tube, or multiple multi-pass tubes; and ii) adjusting thermal input into the multiple parallel tubes, multiple segments of a multi-pass tube, or multiple multi-pass tubes along the transverse dimension W.

Some methods for producing steam of a desired quality comprise flowing water through an inlet to enter a tube of length L under pressure and irradiating the tube along its length to provide thermal input to the tube so that steam exits the tube. The methods comprise using a predicted thermal input as input to a control scheme to control quality of steam that exits the tube. The methods in some variations comprise adjusting a mass flow of water into the inlet using a control system (e.g. feedforward control) that utilizes the estimated thermal input to control quality of steam that exits the tube. In some variations, the predicted thermal input may comprise a modeled, tabulated, measured, or estimated time-dependent thermal input. For example, any one of or any combination of daily variations in thermal input due to diurnal motion of the sun, seasonal variations in insolation, or shadows moving across a solar array over the course of a day, can be looked up (e.g. in a lookup table) or measured and provided as input to a control scheme. In another example, the predicted thermal input may incorporate an estimate of thermal losses based on measured process temperatures and a thermal loss model that can be either analytically or empirically derived. In a multi-tube solar boiler, a multi-tube receiver, or a multi-pass receiver having two or more absorber tubes, thermal output (e.g. a temperature measurement or steam output) from one tube can be used as predicted thermal input to a second tube. In some variations, the methods comprise separating water from a steam/water mixture that exits the tube using a separator (e.g. a steam drum or a steam accumulator) and estimating a thermal input to the tube using steam flow out of the separator. In some variations, pressure in a steam drum, liquid level in a steam drum, steam mass flow from the steam drum, and liquid mass flow from the steam drum may be used to estimate thermal input. In some variations, the methods comprise using a predicted thermal input and input from one or more additional control variables (e.g. temperature in an economizer region, temperature at an inlet, temperature at or near a tube exit, pressure, optical input such as DNI, change in tube length, or estimated or measured steam quality) as input to a control system to control steam quality. For example, some methods employ a control scheme wherein temperature in the economizer region and a predicted thermal input are used as control variables to adjust mass flow of water into the tube to control steam quality. Some methods employ a control scheme wherein a change in length of the tube (e.g., change in length between the inlet and an anchored position P that extends further from the inlet than a boiling boundary) and a predicted thermal input are used as control variables to adjust mass flow of water into the tube.

Variations of solar boilers and systems for producing steam are described here. Some variations of solar boilers comprise a tube having an inlet for receiving water and an outlet, a control valve capable of regulating mass flow of water into the inlet, and a controller for controlling a position of the control valve. Alternatively, a flow controlling orifice may be used alone or in conjunction with the control valve to regulate mass flow of water into the inlet of the tube. In some variations, the tube is anchored at a position P between the inlet and the outlet, where the position P extends further from the inlet along the tube than a boiling boundary that occurs in use. In the solar boilers, a measurement of a change in tube length (e.g., between the inlet and position P) is provided as input to the controller, and the controller controls mass flow of water into the inlet to control quality of steam exiting the tube.

Variations of solar boilers comprise a receiver comprising multiple parallel tubes or multiple multi-pass tubes t_(i) extending along the length of the receiver, where i=1, . . . , k, one or more linear Fresnel reflectors configured to rotate about a single axis that is parallel to the receiver to track diurnal motion of the sun, one or more temperature sensors TC_(i) positioned to sense fluid temperature in an economizer region of each of the tubes t_(i) and a controller, wherein output from each of the temperature sensors TC_(i) is provided as input to the controller and used by the controller to adjust a position of the control valve associated with tube t_(i) so as to control mass flow of water into the tube t_(i) and to control steam quality that exits the receiver. Alternatively, a flow controlling orifice may be used alone or in conjunction with the valve to control mass flow of water into the tube t_(i) and to control steam quality that exits the receiver.

Any of the methods, systems, or solar boilers described herein can be used to produce steam having a quality of at most about 70%, or about 70% or higher, or for producing superheated steam.

Any of the methods for controlling steam quality can be used in supplying process steam, or in supplying superheated steam. In some variations, the steam generated (e.g. superheated steam) by the methods, systems, and solar boilers described herein can be used to generate electric power.

Any of the methods, systems, or solar boilers described herein can be used to produce steam having a quality of about 70% or higher (70%+/−10%, or 70%+/−5%), or for producing superheated steam (e.g. about 10, about 20, about 30, about 49, about 50, about 60, about 70, about 80, about 90, or about 100 degrees of superheat).

Any of the methods for controlling steam quality described herein can be used in supplying process steam, or in supplying superheated steam. In some variations, the steam generated (e.g. superheated steam) by the methods, systems, and solar boilers described herein can be used to generate electric power.

Any of the methods for controlling steam quality described herein can be used in stand-alone steam generators or stand-alone power generation, or in steam generators that are used in combination with other steam sources or other power sources. For example, any of the methods described herein can be adapted for use with solar booster steam generation, or with hybrid solar/coal or hybrid solar/natural gas plants.

The methods for controlling steam quality described herein can be adapted to a variety of solar boilers having a variety of configurations. For example, variations of the methods for controlling steam quality can be used in single tube solar boilers (e.g. parabolic troughs or a single tube receiver in an LFR array), in multi-tube systems (e.g. multi-line parabolic troughs, or solar arrays with multi-tube receivers), or multi-pass absorber tube systems. Variations of the methods for controlling steam quality can be adapted for solar boilers comprising recirculation systems. Variations of the methods for controlling steam quality can be adapted for once-through steam generators that employ no recirculation systems.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 illustrates a solar boiler tube that includes an economizer section, an evaporator section, and a superheated steam section.

FIG. 2 illustrates an example of a steam generating system that includes a solar boiler tube.

FIGS. 3A-3D illustrate examples of LFR systems in which transverse thermal input across a width of a receiver and/or longitudinal thermal input along a length of a receiver can by varied by controlling reflectors.

FIG. 4A illustrates an example of a control system for controlling mass flow into a solar boiler tube using any suitable process control variable; FIG. 4B illustrates an example of a control system for controlling mass flow into a solar boiler tube using temperature in the economizer region as a process control variable; FIG. 4C illustrates an example of a control system for a multi-tube system such as a multi-tube receiver; FIG. 4D illustrates an example of a control system for controlling steam quality by controlling mass flow into a solar boiler tube using a change in tube length as a process control variable.

FIGS. 5A-5C illustrates an example of a control system for a multi-tube receiver using temperature as a process control variable.

FIGS. 6A-6C illustrate various configurations for control valve manifolds.

FIG. 7 illustrates an example of a control system that incorporates a predictor, such as a Smith predictor.

FIG. 8 illustrates an example of a control system that uses a predicted thermal input as input to a control scheme. In this particular example, the control scheme is configured so that the predicted thermal input is provided as feedforward input.

FIG. 9A illustrates an example of a control system for a solar array in which multiple receivers are arranged in a parallel configuration, where each receiver contains a single boiler tube; FIG. 9B illustrates an example of a control system for a solar array in which multiple receivers are arranged in a parallel configuration, where each receiver contains multiple parallel-connected boiler tubes.

FIGS. 10A-10B illustrate examples of control systems for a solar boiler tube that can be used during warm up.

FIG. 11 illustrates an example of a LFR system configured for utilizing superheated steam that includes a heating system comprising an LFR system and a reflector system having one or more solar boiler tubes, a steam turbine for receiving superheated steam, and an electrical generator associated with the steam turbine and from which electricity is generated.

FIG. 12 illustrates various aspects that may be included in a power plant configured for utilizing superheated steam, including e.g. a condenser, a thermal energy storage system, and a recirculation system.

FIGS. 13A-13B illustrate examples of a system for generating superheated steam using at least two series of receivers, each containing one or more boiler tubes, with a first receiver in series generating saturated steam that is fed into the second receiver system in the series from which superheated steam is generated, e.g. to power a steam turbine. A separator and recirculation system may be configured to the outlet of the first receiver and optionally to the second receiver. The second receiver may in one variation be replaced by an external heat source, such as a coal-fired or natural gas fired boiler to generate superheated steam.

FIG. 14 illustrates an example of a system for generating superheated steam using a single receiver containing one or more boiler tubes, where water is introduced into the inlet of the receiver system, which is converted to saturated steam and then to superheated steam before the outlet of the receiver. Optionally, superheated steam is utilized by a steam turbine.

FIGS. 15A-15D illustrate exemplary sensor positions in a receiver comprising multiple absorber tubes.

FIG. 16 shows an example of an LFR that comprises a field of ground-mounted reflectors that are arrayed in parallel rows, and elevated receivers positioned to receive and absorb reflected radiation from the reflectors.

FIG. 17 shows an aerial view of a terminal end of an LFR system.

FIG. 18 illustrates the reflection of solar radiation from four reflectors to two receivers within an LFR system.

FIG. 19 illustrates an example of an absorber tube piping configuration, including riser and downcomer designs that allow for thermal expansion.

FIG. 20 shows an example of a receiver containing one or more boiler tubes where, for illustration purposes only, the number of parallel-connected tubes in the receiver is 5. The boiler tubes are housed in the receiver. Optionally, as shown at the terminus of the receiver, the boiler tubes can be supported on rollers that allow the tubes to expand and contract with thermal change without causing damage to themselves or other portions of the receiver.

FIG. 21 illustrates an array of reflectors where the angled position of each row of linearly coupled reflectors is controlled by a drive located at a terminus of the row.

FIG. 22 illustrates an array of reflectors where the angled position of each row of linearly coupled reflectors is controlled by a drive located at a central region of the row.

FIG. 23 illustrates a field of single reflectors that are each individually controlled by a drive located at a terminus.

FIG. 24 illustrates an example of a control system for a recirculation pump in a solar energy collector system.

FIG. 25 illustrates an example of a control scheme for a system in which saturated steam is generated in a first solar boiler and the saturated steam is supplied to a second solar boiler in series with the first to generate superheated steam.

FIG. 26 illustrates an example of a control scheme for generating superheated steam in a solar boiler.

DETAILED DESCRIPTION

Methods and systems for generating steam using solar energy are described herein. The methods and systems can be used to generate steam of a desired quality at a delivery pressure, e.g. saturated steam having about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, or about 90% quality, or superheated steam. The steam generated by the methods and systems described herein can be used directly, e.g. as process steam for applications such as food processing, enhanced oil recovery, agricultural processing, pulp and paper processing, industrial processes, heating and cooling, and the like, or to power a turbine to generate electrical power. The delivery pressure of the generated steam can be selected for a particular application, e.g. about 600-2800 psi. However, it should be appreciated that other applications may require other delivery pressures.

Variations of the methods and systems for controlling output steam quality described herein are applicable to solar thermal systems employing a single absorber tube, those employing multiple parallel-connected absorber tubes, and those employing multi-pass absorber tubes. The methods and systems allow improved production of a desired steam quality or superheated steam, where steam quality and steam output can be controlled within a desired range even in the event of systematic or transient variations in insolation that results in systematic or transient variations in thermal input to the absorber tubes. The methods and systems may allow sufficient control to produce steam with a target exit quality (e.g. about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, or about 90%, such as a steam quality of 70%+/−10% or about 70%+/−5%) while operating with sufficient flow to avoid dry out in any tube in the system, and to avoid situations where the solar boiler reaches a trip condition, e.g. due to low flow when thermal input is low.

Any of the systems and methods described herein may be used in conjunction with a solar energy collector system that is used as a stand-alone steam generator or electric power generator, or that is used in combination with another steam generating plant or electric power generator. For example, the methods and systems may be used in conjunction with a solar energy collector system that is used during relatively high insolation periods to augment output of an existing steam plant or power plant (e.g. one that uses coal, natural gas, biomass, oil, or nuclear energy as a fuel source). In some variations, the methods and systems described herein may be used in a configuration where natural gas, coal, nuclear energy, or another type of fuel is used to augment output of a solar thermal steam plant or power plant. In some situations, the methods and systems described herein may be used in conjunction with hybrid steam plants or power plants that are designed so that output (power or steam) is switchable so that output is entirely generated by solar energy, entirely generated by another fuel source such as coal, natural gas, or nuclear energy, or generated by a combination of solar energy and a non-solar fuel source.

Variations of the methods and systems described herein comprise controlling steam exit quality from an absorber tube by controlling mass flow into the absorber tube using an open or closed loop control system in which a measurement of one or more process variables is provided as feedback and/or feedforward input into a controller that controls mass flow into an absorber tube, e.g. by controlling a valve position and/or using various fixed-size orifices. For example, a measurement of any one of or any combination of the process variables including feedwater temperature, temperature in the economizer region of an absorber tube, temperature at or near a tube exit, measured or estimated steam quality exiting an absorber tube, a change in length of a tube or of a segment of an absorber tube, solar input such as direct normal irradiance (DNI), thermal input (e.g. predicted, measured, modeled, tabulated or estimated thermal input) for an absorber tube and pressure can be used as input into a controller that controls mass flow into an absorber tube. In one example, the predicted thermal input may incorporate an estimate of thermal losses based on measured process temperatures and a thermal loss model that can be either analytically or empirically derived. Also described herein are methods and systems for controlling steam quality that involve i) controlling mass flow of water into an absorber tube using feedback and/or feedforward input from a process variable as described above; and ii) controlling thermal input to one or more absorber tubes by adjusting one or more reflectors directing solar radiation to the absorber tube by defocusing, dithering and/or redirecting radiation at the receiver. Variations of the methods and systems described herein include predictive control, where a detected or anticipated change in thermal input is provided as input to a feedforward or feedback control loop. Such predictive control can be used in a multi-tube receiver or multi-pass receiver having two or more absorber tubes, where information about thermal input gleaned from one tube is provided as input to control another tube, and in multi-line systems, where information about thermal input gleaned from one line is used in the control of another line. For example, a change in thermal input can be indicated by a change in temperature that has occurred at or near an exit of a tube, and that information can be provided to adjust a mass flow into that tube or another tube. In a multi-tube receiver or multi-pass receiver having two or more absorber tubes, a change in thermal input indicated in one tube (e.g., the tube with the fastest transit time down the length of the tube due to highest thermal input) can be provided as information to adjust a mass flow in another tube with a slower transit time due to lower thermal input. Variations of the methods and control systems as described herein may be adapted to a single tube system (e.g. a single tube receiver in an LFR system or a single line parabolic trough system), a system comprising multiple parallel-connected tubes in a single receiver (e.g. an LFR solar array comprising a line in which the receiver comprises multiple parallel tubes), a system comprising multiple single tube lines (e.g. an LFR solar array comprising multiple single-tube receivers or a multi-line parabolic trough system), a LFR system comprising multiple receivers, each receiver comprising multiple parallel-connected tubes, or multi-pass systems having one or more absorber tubes.

In any of the examples described herein, mass flow rates and pressure into a tube may be controlled with one or more flow control devices (e.g. valves and/or flow controlling orifices), and flow out of a tube may be controlled with one or more flow control devices (e.g. valves and/or flow controlling orifices). A flow controlling orifice may be a device that restricts flow (e.g. by having a reduced inner diameter) and/or modifies flow, e.g. to reduce turbulence, bubbles, rotational flow, or the like. A flow control device may be active (e.g. a valve that can be adjusted) or passive (a fixed diameter orifice or a valve that is fixed). In some cases, a valve may be used to determine a desired orifice size or during setup of a system, and subsequently the valve may be replaced by the orifice.

The methods and systems described herein can be used in any solar thermal system in which steam is generated in an elongated tube, e.g. linear Fresnel reflector (LFR) solar arrays or parabolic trough systems. LFR systems employ a field of reflectors that direct incident solar radiation to one or more elevated, elongated receivers. An elevated receiver comprises one or more absorber tubes to carry a heat exchange fluid, such as water and/or steam. The one or more absorber tubes absorb incident solar radiation so as to transfer thermal energy to the heat exchange fluid. In some variations, a receiver in an LFR system may comprise a plurality of parallel absorber tubes extending along a length of a receiver. Examples of multi-tube receivers are described in International Patent Application No. PCT/AU2005/000208, filed 17 Feb. 2005 and in U.S. patent application Ser. No. 12/012,829 filed 5 Feb. 2008, each of which is incorporated by reference herein in its entirety. In some variations, a receiver in an LFR system may comprise one or more absorber tubes arranged in a multi-pass configuration. Multi-pass solar thermal systems are described in U.S. provisional patent application entitled “Multi-Tube Solar Thermal Receiver”, application Ser. No. 61/303,615, inventors Peter L. Johnson, Robert J. Hanson, and William M. Conlon, and filed on Feb. 11, 2010, which is incorporated herein by reference in its entirety. Examples of suitable reflectors and reflector systems that rotate about a single axis to track motion of the sun for LFR systems utilizing either single absorber tube receivers, multi-tube receivers, or multi-pass absorber tube systems are provided in U.S. Patent No. International Patent Application Nos. PCT/AU2004/000883 filed 1 Jul. 2004, International Patent Application No. PCT/AU2004/000884 filed 1 Jul. 2004, and U.S. patent application Ser. No. 12/012,829 filed 5 Feb. 2008, each of which is incorporated by reference herein in its entirety.

In some variations, a solar selective coating may be disposed on an absorber tube, for example a solar selective coating that has been designed to increase absorptivity over the received solar spectrum (e.g. DNI at Air Mass 1.5), while reducing loss of heat through thermal emission. Examples of suitable solar selective coatings are described in U.S. Pat. No. 6,632,542 to Maloney et al., and U.S. Pat. No. 5,523,132 to Zhang et al., each of which is incorporated by reference in its entirety.

In one aspect, a solar thermal steam generator that is capable of generating superheated steam (that may, in turn, be used to drive a turbine to generate electric power) or saturated steam of a desired steam quality and that comprises a field of linear Fresnel reflectors directing solar radiation to an elevated receiver comprising one or more absorber tubes (e.g. multiple parallel-connected absorber tubes housed in a single elevated receiver) or one or more absorber tubes arranged in a multi-pass configuration is provided. The LFR system preferably allows control of the amount and/or quality of saturated or superheated steam. Such control may include an adjustment to optimize output (steam quality and/or quantity) in response to a measurement of one or more system parameters that indicates that optimization is desired and/or possible, or in anticipation that optimization will be desired and/or will be possible.

In one aspect, systems comprising a field of linear Fresnel reflectors configured to direct solar radiation to an elevated receiver comprising multiple parallel-connected absorber tubes or multi-pass configured absorber tubes are provided, and a control system configured to decrease a temperature difference between at least two of the absorber tubes in the receiver are described. In one variation, the control system is configured to decrease a temperature difference and/or a length difference between at least two absorber tubes by modifying the mass flow rate of water into an absorber tube and/or causing incremental reflector movements in one or more reflectors in the reflector field and/or by introducing an attemperating spray into at least one absorber tube. In one variation, the control system is configured to respond to a measurement of any one or more of: feedwater temperature, absorber tube temperature in the economizer region, absorber tube temperature at or near the tube exit, mass flow rate, pressure, measured or estimated steam quality, thermal input (predicted, measured, estimated, modeled, or tabulated), and solar input (e.g. DNI).

In the case where a tubing arrangement comprises multiple parallel outbound tubes and/or multiple parallel return tubes, a single flow control device may be used to control mass flow rates into the multiple parallel tubes, and/or a single flow control device may be used to control flow out of multiple parallel return tubes. In other variations, a separate flow control device (e.g. a valve or an orifice) can be used on each outbound tube and/or on each return tube. In some cases, more than one flow control device may be used in combination, e.g. a flow controlling orifice may be used in series with a valve. In tubing arrangements in which multiple tubes in an upstream loop are branched into multiple tubes in a down stream loop, a flow control device can be used between the upstream loop and the downstream loop (e.g. at a turnaround region) to reduce or prevent flow imbalance from developing in the downstream loop or to control the amount and/or quality of steam produced. In some cases, a flow control device on a tube in an upstream loop (e.g. at an inlet to an upstream loop) can be used to control flow in a downstream loop, e.g. where that tube is channeled into a single tube so that the potential for flow imbalance to develop is reduced or to control the amount and/or quality of steam produced. Valves may be selected to modulate control of medium to low flow rates at system pressures up to about 5000 psig. Any suitable valve may be used, e.g. a standard globe control valve sized for ½″, ¾″, or 1″ sizes. However, it should be appreciated by one of ordinary skill that valves of other types and sizes may be used.

Steam quality x is x=(h−h_(f))/h_(fg), where h is the enthalpy of the fluid produced, h_(f) is the enthalpy of saturated liquid, and h_(fg)=h_(g)−h_(f), the difference between the enthalpy of the saturated vapor h_(g) and h_(f). For saturated steam, steam quality is the mass fraction of vapor in a two-phase mixture of water and vapor. For saturated steam, a steam quality of unity indicates no liquid, and a steam quality of zero indicates no vapor. For superheated steam, x will be greater than or equal to one. The control of steam quality is important to any type of boiler. For example, steam quality may determine in part certain grades of boiler pipes that are required for certain applications, expected operating conditions, and equipment lifetime. Steam quality control may be important for intended uses of steam such as driving a turbine or for use in enhanced oil recovery. Steam quality can be affected by any one of or any combination of flow rate through a boiler tube, pressure drop along a boiler tube, and heat flux to a boiler tube. Steam quality can be difficult to measure, especially in high pressure steam systems. In some instances, a separator is used to separate vapor from water to determine steam quality. In some instances, imaging techniques may be used such as X-ray computed tomography. In some instances, steam quality can be determined or estimated by comparing heat output to heat input. In some situations, the concentration of dissolved solids between the inlet and the outlet can be used to estimate steam quality. While specific methods for determining steam quality are discussed above, it should be appreciated by one of ordinary skill that any method or apparatus for determining or measuring steam quality may be used.

In a solar boiler, one or more elongated boiler tubes can be disposed above one or more mirrors. Each boiler tube is fed with feedwater, which typically enters the tube as a subcooled liquid. As sunlight is reflected onto a boiler tube, heat generated by absorption of solar radiation at the tube is transferred into the fluid. Three distinct sections can be identified within a boiler tube, with reference to FIG. 1 below for a boiler tube of length L: A) an economizer section; B) an evaporator section; and C) a superheated steam section. All steam generators include A) and B); only some steam generators will include C). In any of these sections, the exterior temperature of the boiler wall T_(wall) can be determined by {dot over (Q)}_(in)=HTC*(T_(wall)−T_(fluid)), where {dot over (Q)}_(in) is the heat flux in, and HTC is the heat transfer coefficient.

The economizer or sensible heat section (A) occurs just beyond an inlet in which feedwater is fed into a tube. In the economizer section, temperature of the fluid increases from the temperature of the feedwater (T_(fw)) until it reaches a saturation temperature T_(sat), corresponding to the pressure in the tube. Although subcooled nucleate boiling may occur in the economizer region, the average enthalpy of the fluid at any cross section within the economizer region is still subcooled. The economizer region ends at a position λ, which occurs when the bulk fluid is saturated liquid, where it contains the maximum amount of thermal energy that is possible before boiling.

The evaporator section (labeled B) begins after position λ. There, additional thermal energy causes the fluid to boil, increasing the steam quality x of the mixture. The temperature may stay relatively constant in the evaporator section as shown, or may decrease somewhat as energy is absorbed by the heat of evaporation. In some variations, the thermal input, tube pressure, flow rate, and tube length may be such that essentially full evaporation occurs so that the steam quality approaches unity at the dry point γ within the tube. In some cases, any one of or any combination of the preceding factors (thermal input, tube pressure, flow rate, and tube length) may be such that a steam exit quality is less than one. In the latter situations, it is desirable to control the exit steam quality, e.g. to about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, or about 0.9. For example, it may be desirable to control steam quality to be about 0.7, e.g. 0.7+/−10% or 0.7+/−5% for certain applications such as enhanced oil recovery.

In some variations, the thermal input, tube pressure, flow rate and tube length may be such that a superheated steam region (labeled C) is reached, starting at a point γ. In the superheat region, additional thermal input causes sensible heating of the vapor phase. While the regions of a boiler tube are described above with respect to a single-pass tube, it should be appreciated that in a multi-pass tube having total length L, the regions may be located on any segment (corresponding to each pass) of the multi-pass tube and the distances λ, γ, and L may be measured from the inlet of the tube and along each segment.

Referring now to FIG. 2, a variation of a steam generator is illustrated. Steam generator 100 comprises an elongated tube 101 having an end-to-end physical length L. In some variations, the steam generator 100 is any type of steam generator in which the heat flux applied to the tube 101 is relatively uniform along an illuminated length L_(illum), where L_(illum) comprises a substantial portion of the physical length L of the tube 101. For example, the steam generator 100 may comprise a single absorber tube or multi-tube receiver in a LFR solar array, where L_(illum) may be essentially equal to L, or L_(illum) may be somewhat less than L due to potential shading effects at the entrance 121 and/or the exit end 123 of tube 101. In other variations, the steam generator 100 may comprise an elongated tube formed from a series of end-to-end connected parabolic trough sections, where L_(illum) may be essentially equal to L. In yet another variation, the steam generator 100 may comprise one or more multi-pass absorber tubes in a LFR solar array, where each has an end-to-end physical length L and where each segment of the tube passing through the concentrated region of solar radiation has a length L_(segment). In this variation, L_(illum) may be essentially equal to L_(segment), or L_(illum) may be somewhat less than L_(segment) due to potential shading effects at the entrance 121 and/or the exit end 123 of tube 101. The steam generator 100 can be a stand-alone steam generator, can be used to augment steam generated by another source, or can be used in parallel with steam from another source, as described above. In some variations the ratio L_(illum)/L may be about 70%, about 75%, about 80%, about 85%, about 90%, or about 95%.

The physical length L of a tube may be any suitable length. For example, L may be determined by any one of or any combination of two or more of the following factors: tube diameter, operating pressure/temperature, tube composition (e.g. stainless steel or carbon steel), ease of handling during manufacture or installation, size of solar field, diameter of tube, desired steam quality, and the like. In some variations, a tube may comprise multiple tube sections connected together in series in an end-to-end fashion. For example, in an LFR solar array, an absorber tube in a receiver may comprise standard commercially-available lengths of tubing connected together to reach a physical length of about 300 to about 400 meters, e.g. about 384 meters. The tube materials and construction may be selected to meet local or industry standards or codes for the particular operating conditions (e.g. temperature and pressure) of the steam generator, e.g. local or national boiler codes.

The illuminated length L_(illum) of an absorber tube can be measured, calculated, or estimated. One example of a calculation for L_(illum) is as follows. The solar position can be determined for the location of the tube, comprising the azimuthal angle az and the zenith ze. The rotation of the tube rot in degrees relative to straight north can be determined. The height of the tube h_(tube) relative to the focal point of one or more reflectors directing solar energy to the tube may be determined. For example, in a LFR system, h_(tube) may be about 10 meters, about 12 meters, about 15 meters, about 18 meters, about 20 meters, or about 25 meters. The length of a shaded section l_(dark) for a reflector positioned directly beneath a tube is approximated by l_(dark)=h_(tube) tan(ze) cos(az−rot+180). The illuminated length can be approximated as L_(illum)=L−l_(dark). Reflectors that are positioned in a reflector field at farther distances from a receiver may have longer shaded sections. The effects for such longer shaded lengths may be calculated, the same shaded length may be used for all reflectors regardless of distance from the receiver, or the actual shaded length may be calculated for some reflectors in a field (e.g. the outermost reflectors positioned furthest from the receiver) and approximated shaded length using l_(dark) for a reflector positioned directly beneath the receiver may be used for some reflectors in the field (e.g. those positioned closest to the receiver).

Referring again to FIG. 2, within the tube 101 an economizer section 103 and a saturated steam section 105 are included. Thus, in operation, there is a boiling point boundary 117 that occurs at a length λ from inlet 121. In certain variations where superheated steam is formed within the tube 101, there is a dryout point 128 that occurs at a length γ from inlet 121. As indicated by arrow 119, thermal input {dot over (Q)}_(in) is provided along the illumination length L_(illum) of the tube 101. Again, the illumination length L_(illum) may or may not be the same as the physical length L, depending on whether there are dark regions such as shading effects as described above. Solar radiation can be directed to the tube 101 using any suitable reflector configuration, e.g. parabolic troughs, heliostat reflectors, or linear Fresnel reflectors such as illustrated herein or otherwise known.

In some variations, the thermal input {dot over (Q)}_(in) may be relatively uniformly distributed along the length L_(illum); that is, L_(illum) may for example represent a relatively uniformly irradiated portion of the tube 101, e.g. where tube 101 is installed in a parabolic trough system or in a receiver in a linear Fresnel reflector solar array. The thermal input {dot over (Q)}_(in) may vary over time. For example, in a solar array, motion of the sun relative to the earth may cause systematic intra-day and day-to-day variations in irradiation, and therefore in thermal input {dot over (Q)}. In some cases, one or more transient factors such as cloud cover, shadows (e.g. shadows from the solar array itself) or other events such as mirror alignment issues may cause intermittent or non-systematic variability in thermal input.

Water supplied into the inlet 121 of tube 101 has a temperature T_(in), enthalpy h_(in) and mass flow {dot over (m)}_(in). Mass flow into the tube 101 can be regulated with control valve 115. Alternatively, a flow controlling orifice (not shown) may be used alone or in conjunction with flow control valve 115 to control the mass flow entering tube 101. Steam that exits the tube 101 may optionally enter a separator 113 (such as a steam accumulator or a steam drum at pressure P_(drum)), from which a dry steam flow 125 having a mass flow {dot over (m)}_(steam) and enthalpy h_(g) can be extracted. Other types of separators may be used, such as baffles or cyclone separators. In instances where superheated steam is generated in tube 101, a separator may not be necessary. Water recovered from the separator 113 may optionally be used in a recirculation system. For example, if a steam drum is used as a separator, water recovered may have a liquid level L_(drum) in the drum. Recirculated water flow 107 may be extracted from the separator with a mass flow {dot over (m)}_(recirc) and enthalpy h_(f). Feedwater flow 109 with a mass flow {dot over (m)}_(feed) and enthalpy h_(feed) may be mixed with the recirculated water flow 107 to provide input into the tube 101.

As stated above, in an LFR solar array, an elevated receiver can be a single tube receiver, multi-tube receiver, or a multi-pass receiver. For single tube receivers, a tube diameter can be in a range from about 1 inch to about 12 inches, or in a range from about 12 inches to about 24 inches, where a tube diameter selection may depend on factors such as the size of the reflector field being used, the pressure during operation, the temperature during operation, the material and composition of the tube, the amount of steam, and the quality of steam desired. For multi-tube receivers, a tube diameter can be in a range from about 0.5 inches to about 6 inches (e.g. about 0.5 inch, about 1 inch, about 1.25 inches, about 1.5 inches, about 1.75 inches, about 2 inches, about 2.5 inches, about 3 inches, about 3.5 inches, about 4 inches, about 4.5 inches, about 5 inches, about 5.5 inches, or about 6 inches), again depending on such factors as the size of the reflector field being used, the pressure and temperature during operation, the material composition and structure of the tubes, the steam flow required, and the steam quality desired. Any suitable number of tubes may be used for a receiver, e.g. 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, or 12 tubes, or even more. For multi-pass receivers, the diameter of the return tube can be selected to be larger than that of the outbound tubes, e.g. the outbound tubes can have an inner or outer diameter ranging from 1″ to 6″, for example, 1.5″, 1.66″, 2.0″, or 2.5″, and the return tube can have an inner or outer diameter ranging from 1″ to 9″, for example, 0.5″, 1.0″, or 1.5″ larger than that of the outbound tubes. In some variations, 2″ inner or outer diameter outbound tubes are used with a 3″ inner or outer diameter return tube, and in some variations, 1.66″ inner or outer diameter outbound tubes are used with a 3.5″ inner or outer diameter return tube. While example diameters have been provided, it should be appreciated by one of ordinary skill that tubes having other diameters may be used. Single, multi-tube, or multi-pass receivers may have various attributes for improving efficiency or performance, such as solar selective coatings applied to the tubes and/or cavities for trapping thermal energy such as an inverted trough cavity for housing one or more tubes as described in U.S. patent application Ser. No. 12/012,829 which is incorporated by reference herein in its entirety, insulation placed near or around nonirradiated sections of the tube to reduce thermal losses, and roofs and the like to reduce thermal losses and/or protect tubes from environmental effects. Tubes in a multi-tube or multi-pass receiver may be arranged side-by-side in a single row (e.g. a planar array), or in more than one row (a nonplanar array). Tubes may be supported below by one or more rollers to accommodate thermal expansion in the length of the tube, e.g. as described in International Patent Application No. PCT/AU2005/000208 and U.S. patent application Ser. No. 12/012,829, each of which is incorporated by reference herein in its entirety.

The amount of solar radiation incident on an absorber tube, and hence thermal input, can be varied. In some variations it may be desired to adjust the total system thermal input while maintaining the distribution of thermal input along the illuminated length of the tube. An example of an LFR solar array utilizing a multi-tube tube solar receiver is illustrated in FIG. 3A. The receiver 300 comprises multiple elongated tubes 301 extending along the length of the receiver. A field of elongated reflectors 306 in rows that can be rotated about a single axis parallel to the elongated receiver 300 directs solar radiation to the tubes 301. By adjusting the angle of one or more reflectors so that reflected solar radiation is defocused, displaced, dithered, or partially or completely misses the receiver, the thermal input across a transverse dimension 305 of the receiver 300 can be varied. In some variations, the thermal input across a transverse dimension 305 can be varied while maintaining a relatively constant thermal input along the illumination length of each receiver tube 301. Similarly, for a multi-pass absorber tube system, by adjusting the angle of one or more reflectors so that reflected solar radiation is defocused, displaced, dithered, or partially or completely misses the receiver, the thermal input across a transverse dimension of the multi-pass receiver can be varied. In some variations, the thermal input across the transverse dimension can be varied while maintaining a relatively constant thermal input along the illumination length of each receiver segment of each multi-pass tube. Similarly, for a single tube system such as a single tube LFR solar collector system, variation of thermal input across a transverse dimension of the single tube (e.g. while maintaining a relatively constant longitudinal thermal input) can be achieved by rotating one or more elongated reflectors directing solar radiation to the single tube about a single axis parallel to the tube. An example of a situation in which thermal input is translated across a transverse dimension of a tube by rotating linear Fresnel reflectors is illustrated in FIG. 3B. There, receiver 320 comprises multiple parallel-connected side-by-side tubes 321. One or more reflector rows (not shown) reflect solar radiation to provide an illuminated band 322 incident on the tubes 321. As indicated by arrows 323, the illuminated band 322 can be translated back and forth across a transverse dimension 324, e.g. so that the illuminated band is centered relative to the tubes 321 or is offset relative to the tubes 321. An example of a situation in which illumination is defocused or focused to change thermal input is illustrated in FIG. 3C. There, a receiver 340 comprises a bank of multiple parallel-connected tubes 341. One or more reflector rows (not shown) reflects solar radiation to provide an illumination band 342 incident on the tubes 341. By defocusing the illumination band to form a broadened band indicated by dashed lines 343, the thermal input to the tubes 341 can be varied. Defocusing can, for example, be achieved in a LFR array having multiple parallel rows of reflectors by rotating one reflector row about a single axis parallel to the tubes 341 to direct light to a somewhat different location along the transverse direction 334 of the receiver 340 than other rows of reflectors. In some cases, a reflector position can be dithered on a relatively rapid timescale e.g. a frequency selected to accommodate mass and structure of reflector structures but sufficiently fast so that irradiation of the pipes is blurred to avoid local heating, which may be about 0.01 to about 50 Hz (e.g. about 0.1 Hz, about 0.5 Hz, about 1 Hz, or about 10 Hz) to adjust transverse heat flux. That is, a reflector can be adjusted back and forth between incremental first and second locations. Although the receivers in FIGS. 3A-3C are illustrated to include multiple tubes, it is to be understood that the concepts illustrated in FIGS. 3A-3C and related discussion and description apply to receivers having single tubes and one or more multi-pass tubes.

Alternatively to or in addition to the adjustment of thermal input across a transverse direction of a receiver (e.g. while maintaining a relatively constant thermal input longitudinally as illustrated in FIGS. 3A-3C), longitudinal adjustments of thermal input are possible using reflectors. An example is illustrated in FIG. 3D. There, an elongated reflector row 360 directs solar radiation to an elevated elongated receiver 363 that comprises one or multiple tubes. Reflectors in the reflector row 360 are supported by supports 361. One or more drive mechanisms (not shown) allow the reflectors in the reflector row 360 to be rotated about a single axis 362 that is parallel to the tubes in the elevated receiver. One or more segments 364 of the reflector row 360 can be rotated independently of other segments in the reflector row 360. For example, the reflectors in the segment 364 can be rotated to direct radiation to the receiver, whereas other reflector segments are inverted or otherwise rotated so as to result in a selectively irradiated length 365 of the one or more absorber tubes in the receiver 363, thereby creating a corresponding selectively heated longitudinal section of the absorber tubes. Thermal input can be varied transversely across a receiver (multi-tube, multi-pass tube(s), or single tube), e.g. as illustrated in FIGS. 3A-3C in conjunction with (in parallel with or alternating with) variation of thermal input longitudinally along a length of a receiver, e.g. as illustrated in FIG. 3D. Thermal input can be varied by use of an attemperating spray. An attemperating spray to adjust thermal input can be used in conjunction with (e.g. in parallel with or alternated with) adjustment of reflector position, or an attemperating spray can be used without adjustment of reflector position.

Steam quality (e.g. about 30% about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, or superheated steam) produced by a multi-tube solar receiver, multi-pass solar receiver, or a single tube solar receiver (e.g. linear Fresnel solar receiver or parabolic trough) can be controlled by regulating mass flow of water into the one or more tubes. The process control variable used in a control system that regulates mass flow of water into one or more tubes can be temperature in an economizer region of the tube, feedwater temperature, temperature at or near the exit end of a tube, solar input (e.g. DNI), change in length of a tube or a section of a tube, measured or estimated steam quality, thermal input (e.g. predicted, measured, tabulated or estimated thermal input), pressure, or a combination of two or more of the preceding variables. A control system can include any suitable control scheme, such as a control scheme that includes only feedback control, includes only feedforward control, or includes a combination of feedback and feedforward control. A control system may be set up to control using information from only one process variable, or from multiple process variables. In some variations, cascaded control systems can be used, where an output of one controller is an input to a second controller. The control system may incorporate a proportional controller, a proportional-integral (PI) controller, a proportional-derivative (PD) controller, a proportional-integral-derivative (PID) controller in analog or digital form, or another form of control or modification of one of these control schemes. Some control systems include a feedback control in combination with a feedforward control.

In some variations, predictive control can be used so that an estimate or indication of an upcoming change in a variable (such as a change in thermal input due to transients or other changes in insolation) can be taken into account to improve a response time to that change. Such predictive control can improve control of steam quality in a system with relatively long tubes, e.g. where a transit time from a tube inlet to a tube outlet is on the order of a minute, or several minutes or longer, e.g. an hour or more. In some variations, predictive control can be accomplished by sensing a change in a process variable near the end of the tube, and using that information as a predictor of what is happening further upstream in the tube, and providing that predicted information as input to a control system. In some variations, predictive control can be accomplished by utilizing information gleaned from one tube with a relatively fast transit time, and using that information in a control system controlling a tube having a relatively slow transit time. In some variations, a predictor (e.g. a Smith predictor) may be used to compensate for time delay between an inlet of a tube and a downstream point in the tube at which a process variable is measured. In some variations, temperature in an economizer section of a tube, a change in length of a tube or a section of a tube, estimated or measured steam quality, or thermal input (e.g. measured, estimated, tabulated, or calculated) can be used as a process variable or to provide predictive information to a control scheme that regulates valve position to control mass flow of water into one or more tubes. In some variations, thermal input (e.g. an estimated, measured, tabulated or calculated change in thermal input) is used to provide predictive input (e.g. feedforward input) to a controller operating a valve to control mass flow of water into one or more tubes. In some variations, a detected or anticipated change in thermal input is used to provide predictive input (e.g. in a feedforward control), and one or more of the other process variables (e.g. temperature in an economizer region, feedwater temperature, solar input (e.g. DNI), pressure, temperature near the tube outlet, a change in length of a tube or a section of a tube, or estimated or measured steam quality) is used to provide input (e.g. feedback) into a controller operating a valve to control mass flow of water into one or more tubes. In some variations, a fixed diameter flow controlling orifice may be used alone or in conjunction with the valve. In some variations, a control system that controls mass flow into one or more tubes is coupled to a system that controls reflector position, so that reflector position can be used to adjust transverse and/or longitudinal thermal input into the one or more tubes, e.g. as described above and in connection with FIGS. 3A-3D.

As stated above, variations of the methods and systems described herein include predictive control, where a detected or anticipated change in thermal input or other process variable as described herein is provided as input to a feedforward or feedback control loop. Such predictive control can be used in a multi-tube receiver or a multi-pass receiver having multiple tubes, where information about thermal input or another process variable that is gleaned from one tube is provided as input to control another tube, and in multi-line systems, where information about thermal input or another process variable gleaned from one line is used in the control of another line. For example, a change in thermal input can be indicated by a change in temperature that has occurred at or near an exit of a tube, and that information can be provided to adjust a mass flow into that tube. In a multi-tube receiver or a multi-pass receiver having multiple tubes, a change in thermal input indicated in one tube (e.g., the tube with the fastest transit time down the length of the tube due to highest thermal input) can be provided as predictive information to adjust a mass flow in another tube with a slower transit time due to lower thermal input.

An example of a control system is illustrated in FIG. 4A. There, a steam generating system 400 includes a steam plant 401, which includes at least one or more solar boiler tubes as illustrated in FIG. 2, and may optionally include a separator and a recirculation loop whereby warm water recovered from the separator is mixed with feedwater for subsequent introduction into and reheating in a boiler tube. Associated with the one or more boiler tubes is a control valve manifold (indicated by CV_(k)) and/or fixed diameter flow controlling orifice that regulates mass flow of water into the tubes. Each boiler tube may have a dedicated control valve and/or fixed diameter flow controlling orifice, or a control valve and/or fixed diameter flow controlling orifice may control mass flow of water into more than one tube. A process variable associated with a k^(th) tube PR_(k) (represented by box 403) is measured within the plant. Examples of process variables that can be measured or estimated include thermal input, feedwater temperature, a temperature of water within the economizer region of the tube, temperature of fluid (water, saturated steam, or superheated steam) near the outlet of the tube, an external temperature of the tube surface in its economizer region or near the outlet, measured or estimated steam quality at exit, pressure, solar input (e.g. DNI), or a change in physical length of a tube or a section of a tube, e.g. a section of the tube between the inlet and the boiling boundary λ, or between a floating inlet end of the tube and a position at which the tube is anchored in place, which may be selected to extend further from the inlet than the boiling boundary λ. The process parameter PR_(k) 403 for the k^(th) tube is provided to an operator portion 405 of a controller, e.g. an operator such as a summer. A set point for the physical parameter for the k^(th) tube PR_(set,k) is also provided to the operator portion 405. A set point may, for example, be a temperature set point for a temperature measurement within the economizer region of a tube, a temperature measurement near the tube exit, or a target change in length. A qualitative or quantitative comparison between the set point PR_(set,k) and the measured physical process variable PR_(k) 403 is made by the operator portion 405 of the controller (e.g. by a summer), and the results of that comparison are fed into a main portion 407 of the controller employing any suitable control algorithm, e.g. so as to provide proportional integral (PI) control, proportional-integral derivative control (PID), proportional-derivative control (PD) and the like. Output from the controller 407 is provided to the one or more control valves CV_(k) in the manifold to adjust the valve position to control mass flow of water into the tubes. Although the example illustrated in FIG. 4A shows the control system as a feedback control loop, it is to be understood that other control configurations are contemplated. In some variations employing multi-tube receivers or a multi-pass receivers having multiple tubes, control may be accomplished so that all tubes in the receiver reach approximately the same length and/or temperature at or near the tube exit in steady state operation.

For any of the multi-tube or multi-pass receiver steam generating systems described herein, it is contemplated that a process variable measured for a k^(th) tube may be used as control input for a different tube (not the k^(th) tube). For example, a process variable such as temperature in an economizer region, fluid temperature at or near the end of the tube, estimated or measured steam quality, estimated or measured thermal input, or change in tube length for a k^(th) tube may be used in a control system for a different tube. In some variations, if a first tube has a faster transit time than a second transit tube, it may be desired to provide information about one or more process variables from the first tube as input into a control system for the second tube, e.g. as part of a predictive control algorithm. Control systems employing such cross-tube information may be useful in multi-tube or multi-pass receivers, where a centrally positioned tube may receive a higher level of irradiance and hence exhibit a faster transit time than a tube positioned near the edge.

An example of a control system that can be used to control steam quality in an LFR solar array comprising an elevated receiver that, in turn, comprises multiple parallel-connected absorber tubes is illustrated in FIG. 4B. A reflector field (not shown) provides thermal input to the solar receiver 450. Temperature of one or more of the solar boiler tubes in the economizer region 451 of the receiver is provided as input to an operator portion 452 of a controller. A temperature set point for the k^(th) tube T_(set,k) is provided to the operator 452. Output from the operator portion is provided to a main portion of a controller 455, where as described above, based on a qualitative or quantitative comparison between the temperature set point and measured economizer temperature (e.g. a calculated difference between the measured value and set point), the controller 455 effects an adjustment to a control valve 453 for the k^(th) tube to control mass flow water in the k^(th) tube. Temperature measurement in an economizer section can be used alone or in combination with any other process variable, e.g. in combination with one or more of temperature at or near the tube outlet, estimated or measured thermal input, estimated or measured steam quality, solar input (e.g. DNI), feedwater temperature, change in tube length, and pressure. In some variations, a temperature measurement in an economizer region of a k^(th) tube can be used as a process control variable for a different tube (not the k^(th) tube). For example, if a transit time in a first tube is faster than in a second tube, it may be desired to use the temperature in the economizer region or a change in length of the first tube with a relatively fast transit time as input into a control system for the second tube with a relatively slow transit time, for example where the measurement of the temperature or length change in the first tube is providing predictive information for the control system for the second tube. Although the example illustrated in FIG. 4B shows a feedback control loop, it is to be understood that that other control configurations for controlling mass flow into a tube using temperature in an economizer region of a tube are contemplated, e.g. a feedforward control system or cascaded control. Additionally, while the example illustrated in FIG. 4B comprises a receiver having multiple parallel-connected absorber tubes, it should be appreciated that the control system described above may similarly be applied to a multi-pass receiver having two or more absorber tubes.

Temperature measurement in the economizer region or at or near the exit of the tube can be made using any suitable method, e.g. using a thermocouple or other thermal sensor welded or otherwise thermally coupled to a metal exterior of the tube, an infrared temperature sensing device, a temperature sensor such as a thermocouple inserted into the tube via a well (a thermowell), and the like. The temperature set point T_(set) can be determined using any suitable method. (Note that T_(set) refers to the temperature set point used by a controller, and in some variations different set points may be used for individual tubes, so that the set point for the k^(th) tube is referred to as T_(set,k)). In some situations, the temperature set point can be determined based on the position of the temperature measurement (e.g. position of a thermocouple) relative to the tube inlet, target heat enthalpy h_(target) of the fluid that exits the tube, and the illumination length of the tube L_(illum) (which may in certain variations be essentially the same as the physical length L of the tube as described above). The temperature set point T_(set) can be such that

${\frac{c_{p}\left( {T_{set} - T_{in}} \right)}{l_{TC}} = \frac{\left( {h_{target} - {c_{p}T_{in}}} \right)}{L_{illum}}},$

where h_(t arg et)=h_(f)+x_(t arg et)h_(fg), x_(t arg et)=x+x_bias, and h_(fg) refers to the enthalpy required to change from a saturated liquid to a saturated vapor (h_(g)−h_(f)), h_(g) refers to the enthalpy of saturated vapor, c_(p) refers to the heat capacity of fluid under the operating conditions, T_(in) is the temperature of the water at the tube inlet, l_(TC) refers to the position of the temperature sensor relative to the tube inlet, and x_bias refers to an auxiliary offset (manual or automatic). It should be noted that in some variations, temperature can be measured at two or more locations within an economizer region (l₁ and l₂) and the change in temperature between the locations l₁ and l₂ can be used as a process control variable and/or in setting the temperature set point. As stated above, a temperature set point can be set for an individual tube (T_(set,k)), the same set point can be used for multiple tubes (e.g. neighboring tubes, or tubes symmetrically placed in the receiver relative to each other such as two tubes on the ends), or the same set point can be used for all tubes. Thus, the auxiliary offset can be set for an individual tube in some variations, in which case x_bias_(k) for that individual tube could be used in determining a set point.

An example of a control system for a multi-tube solar array (e.g. one comprising a multi-tube receiver, or multiple single tube receivers) or multi-pass solar array comprising a receiver having two or more absorber tubes is provided in FIG. 4C. The steam generating system 430 includes a plant 424 that includes multiple solar boiler tubes, and may optionally include a separator (e.g. a steam drum) and a recirculation system as described herein. There, a process control variable PR_(k) 425 for the k^(th) tube PR_(k) is provided as input to an operator (e.g. a summer) portion 420 of a controller, which is provided to a main portion of a controller 421. The process control variable PR_(k) can be any suitable variable, such as any one of or any combination of feedwater temperature, temperature in an economizer region of a tube, temperature at or near the tube outlet, change in length of tube or length of a section of a tube, measured or estimated steam quality, measured or estimated solar input (e.g. DNI), measured or estimated thermal input, and pressure. The controller uses any suitable algorithm (e.g. PI, PD, or PID control) to determine a proportionality constant for the k^(th) tube, α_(k). A mass flow into an individual tube {dot over (m)}_(in,k) can then be determined: {dot over (m)}_(in,k)=a_(k){dot over (m)}_(in) using a multiplier 422, which may be integral with the controller or may be a separate device. The output from the multiplier can then be used to adjust a valve position and/or diameter of a flow controlling orifice, using a function to correlate mass flow to valve position and/or diameter of a flow controlling orifice. In some variations, information about one or more process control variables from one tube may be used as input to a controller or control channel that is controlling mass flow into another tube. Such cross-tube control may, for example, be desirable in a multi-tube receiver or multi-pass receiver having two or more absorber tubes. Although the control system in FIG. 4C is depicted as feedback control, any suitable control configuration can be used, e.g. feedforward control or cascaded control.

Another example of a control system that can be used to control steam quality in a single, multi-tube, or multi-pass solar array (e.g. parabolic trough or single or multi-tube or multiple pass LFR array) is illustrated in FIG. 4D. As a boiler tube is heated, it undergoes thermal expansion as a function of temperature: dL/dT=Lα_(TE), where dL/dT is the change in tube length per temperature change, and α_(TE) is the coefficient of linear thermal expansion for the pipe material, which may be a type of steel selected for the particular operating conditions of the boiler (pressures, temperatures, environmental, and the like), e.g. carbon steel or stainless steel. A change in tube length for a section of a tube can be used to represent an integrated change in temperature over that section. A change in tube length can be measured, or a change in length of a section of a tube can be measured, and used as a process control variable for a control system that controls quality of steam output, and in some variations a change in length of one tube can be used as predictive control information for a second tube (e.g. in a multi-tube receiver). For example, if a boiler tube is fixed in position in a central region, and allowed to expand at each end, a measurement of the change in length of the tube relative to the fixed position can be used as a process control variable. For example, if a boiler tube is fixed or anchored in position in the evaporator section, the length of the tube between the inlet and the anchored position can be measured over time. By neglecting any change in temperature that occurs in the relatively isothermal evaporator section, a change in the tube length can be attributed to integrated change in temperature in the economizer section. By using tube length between an inlet and a point beyond the boiling boundary λ, as a measure, integration over all temperature points in the economizer section is accomplished. Referring back to FIG. 4D, an absorber tube 470 is relatively free floating at its inlet end 471, but is fixed in position at a point 473 between the inlet 471 and the outlet 472. The tube, when cold, has a physical end-to-end length L_(cold). A change in length ΔL of the length L_(segment) of the tube between the inlet 471 and the anchored position 473 can be measured. Change in length can be measured using any suitable technique, e.g. using an optical detector, a ruler or scale, stress or strain indicator, or any kind of device that measures physical displacement such as a caliper, transducer (e.g. linear variable displacement transducer), a compressible spring, and the like. In some variations, a limit indicator may be included so that if the length reaches a certain limit, the limit indicator is activated to reduce thermal input. Such a limit indicator may improve safety. The measured change in length ΔL may be provided as a process variable into a controller input 480, where a qualitative or quantitative comparison (e.g. a difference calculation between measured and set values) between the measured value of change in length and the set point for the k^(th) tube ΔL_(set,k) is provided to an appropriate algorithm in a controller 482 that effects a change in a control valve 483 position to regulate mass flow of water into the k^(th) tube. Change in tube length can be used alone or in combination with one or more other variables in a control system that controls steam quality, e.g. in combination with one or more of: a temperature in an economizer region, temperature at an outlet, estimated or measured thermal input, estimated or measured steam quality, pressure, solar input such as DNI, and feedwater temperature. For example, in some variations, a measured change in length of a tube or a section of tube can be used in combination with a temperature measurement of that tube in its economizer region as input to a controller that controls mass flow of water to that tube. In some variations, a measured change in length of a tube or section of a tube can be used in combination with a steam quality estimate as input to a controller that controls mass flow of water to that tube. In some variations, a measured change in length of a tube or a section of a tube, a temperature measurement of that tube in its economizer region, and an estimated steam quality can be used as input to a controller that controls mass flow of water to that tube. In some variations of multi-tube systems and multi-pass systems comprising a receiver having two or more absorber tubes, a change in length in one tube may be used as input to a control system or channel for another tube in the system (e.g. where a multi-tube receiver or multi-pass receiver with two or more tubes is being used). For example, change in length in a tube with a relatively fast response time may be used as predictive information provided as input to a control system to a tube with a relatively slow response time. Although the control system in FIG. 4D is illustrated as a feedback control system, any suitable control configurations using change in tube length as a process variable can be used, e.g. feedforward control, or cascaded control.

In some variations, it may be desired to estimate steam quality

${x\left( {{e.g.\mspace{14mu} x} \approx \frac{{\overset{.}{m}}_{steam}}{{\overset{.}{m}}_{in}}} \right)},$

where {dot over (m)}_(steam) is the mass flow of steam from a steam drum or accumulator and {dot over (m)}_(in) is the mass flow of water into the steam generator, to compare such estimated steam quality with target steam quality x_(target), and to use the comparison between target and estimated steam quality as input to a controller in a control system (e.g. a feedback control loop or a feedforward control system) to adjust mass flow into one or more of the tubes. Estimated steam quality can be used alone or in combination with one or more other process variables such as feedwater temperature, temperature in an economizer region, temperature at or near a tube exit, solar input such as DNI, estimated or measured thermal input, change in tube length, or pressure.

An example of a control system used in conjunction with a multi-tube receiver or multi-pass receiver comprising two or more absorber tubes, in which k multiple tubes are arranged in parallel is provided in FIGS. 5A-5C. The number of tubes in a receiver may be 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, or even more, e.g. 15 or 20. In the receiver 500, each tube 501(1), . . . , 501(k) comprises a thermal sensor TC_(k) that is positioned on or in the tube (e.g. using a thermowell) at a distance l_(TC,k) from each respective inlet 512(1) . . . 512(k). The distances l_(TC,k) are selected to be within the economizer region of each tube, i.e. before the boiling point boundary (as described in FIG. 2 above) for each respective tube. The temperature measurement device may be any suitable device, e.g. a thermocouple welded or otherwise thermally coupled to a metal exterior of the tube, an infrared temperature sensing device, a thermal sensor (such as a thermocouple) inserted into the tube via a well (a thermowell), and the like. In some variations, the devices TC_(k) may be positioned at identical distances from the respective inlets 512(k). For example, if all tubes have an identical length L, the positions l_(TC,k) may be at about 1/10 L, about ⅛ L, or about ⅙ L (all distances relative to the tube inlet). In other variations, the devices TC_(k) may be positioned at different distances from the respective inlets 512(k). For example, if tubes near the center of a multi-tube receiver or multi-pass receiver comprising two or more absorber tubes tend to receive more thermal input due to a heat flux profile transversely across the receiver, then the boiling boundary in those tubes may occur closer to the inlet, and the position of the temperature measurement device may be adjusted accordingly to be relatively closer to the inlet. As stated above, in some variations, multiple temperature sensors may be placed in an economizer region, and change in temperature between two of these temperature sensors in an economizer region can be used as a process variable, and/or in setting the temperature set point.

In some variations, thermal input for each tube {dot over (Q)}_(in,k) is provided so as to be relatively uniform along the length of the tube. As shown, each of the tubes 501(k) has a physical length L_(k), and an illumination length L_(illum,k) which may or may not be the same as the physical length L_(k) due to effects such as shading at the tube ends. In some variations, all tubes within a single receiver may have the identical physical length L_(k). However, as described above, the illumination length is generally at least about 80% at least about 90%, at least about 95% of the physical length L_(k). The total thermal input to a multi-tube receiver is given by {dot over (Q)}_(in)=Σ₁ ^(k){dot over (Q)}_(in,k).

A mass flow of water {dot over (m)}_(in) at a temperature T_(in) (and having a heat enthalpy h_(in)) is provided into a manifold, where it is split into k branches for feeding into each of the k multiple tubes. Flow into each of the tubes is controlled with a control valve CV_(k) and/or a fixed diameter flow controlling orifice, leading to mass flows into the inlets 512(1) . . . 512(k) of each of the respective individual tubes represented by {dot over (m)}_(in,k), such that {dot over (m)}_(in)=Σ₁ ^(k){dot over (m)}_(in,k). In the systems and methods described herein, any suitable type of control valve can be used, e.g. linear, equal percentage, electric, pneumatic, electropneumatic, or manual.

Although the particular example illustrated in FIGS. 5A-5C shows a control valve and/or a fixed diameter flow controlling orifice regulating mass flow into each of the k tubes, embodiments are contemplated in which a single control valve and/or a fixed diameter flow controlling orifice may control mass flow of water into more than one tube. Examples of such variations are shown in FIGS. 6A-6C. For example, In FIG. 6A, a variation is illustrated in which water mass flow into all tubes is controlled by a single control valve and/or fixed diameter flow controlling orifice. In FIG. 6B, a variation is illustrated in which water mass flow into two neighboring tubes is controlled by a single valve and/or a fixed diameter flow controlling orifice, one variation of which is a configuration in which mass flow into a first half of the tubes is controlled by a first control valve and/or a first fixed diameter flow controlling orifice and water mass flow into a second half of the tubes is controlled by a second control valve and/or a second fixed diameter flow controlling orifice. In FIG. 6C, a variation is illustrated in which water flow into two outermost tubes is controlled by a single valve and/or a fixed diameter flow controlling orifice, and water mass flow into an inner group of three tubes is controlled by a single valve and/or a fixed diameter flow controlling orifice.

Referring back to FIG. 5C, output from the tubes 501(k) is combined, where the combined output of the tubes has a heat enthalpy h_(out). The combined output of the tubes can optionally be fed into a separator 515, which may in some variations comprise a steam drum at a pressure P_(drum). Other types of separators may be used such as baffles and cyclone separators. If superheated steam is being generated in all tube 501(k), a separator may not be necessary. Saturated steam in the separator 515 has a heat enthalpy h_(g) and a mass flow {dot over (m)}_(steam). Steam output from the separator 515 is controlled by valve and/or fixed diameter flow controlling orifice 516. Heated water (saturated liquid) collected by the separator 515 (e.g. water collected in a lower portion of steam drum) has a heat enthalpy of h_(f). Optionally a recirculation system can be used in which water is drawn from the separator 515 and is mixed with a feedwater supply having a mass flow {dot over (m)}_(feed) and enthalpy h_(feed) to provide water input into the tubes 501(k). As illustrated in FIG. 5A, the enthalpy increase of the fluid in a tube between the inlet (h_(in)), the combined outlet h_(out) can be modeled to increase linearly along the length of the tube L in steady state operation. As shown in FIG. 5B (and referring back to FIG. 1), temperature increase of the fluid is a nonlinear function of the tube length, because of the phase change that occurs at the boiling point λ. However, within the economizer region, the temperature increases linearly with length. Thus, a correlation can be made between the linear increase in temperature in the economizer region and the desired increase in enthalpy required to achieve the target enthalpy h_(target), and correspondingly, the target steam quality, as h_(t arg et)=h_(f)+x_(t arg et)h_(fg). The temperature rise in the economizer region can be used as an indicator for whether the target enthalpy is being reached, for example by measuring a temperature difference between two spaced apart thermal sensors, or if one or more temperature sensors TC_(k) is placed at a distance l_(TC) from the inlet within the economizer region, by measuring the temperature at TC_(k) relative to T_(in). The steady state boiling boundary can be estimated:

$\lambda = {l_{TC}{\frac{h_{f} - h_{i}}{h_{TC} - h_{in}}.}}$

Temperature measured in the economizer region by TC_(k) and a temperature set point (e.g. a temperature set point as described above) can be provided as input into a controller that uses a qualitative or quantitative comparison and appropriate control algorithm (e.g. PI or PID) to adjust a control valve position for that tube. The temperature set point can be set for an individual tube within a multi-tube receiver or multi-pass receiver comprising two or more absorber tubes, or the temperature set point can be identical for a subset of tubes within a multi-tube receiver or multi-pass receiver comprising two or more absorber tubes, or the temperature set point can be identical for all tubes within a multi-tube receiver or multi-pass receiver comprising two or more absorber tubes.

Alternatively to or in addition to measuring temperature in an economizer region, a change in tube length or a change in length of a section of a tube as described above (e.g. in connection with FIG. 4D) may be used as a process control variable for a control system that regulates mass flow into tubes in a multi-tube receiver or multi-pass receiver. Using a change in tube length may provide an integrated measure of temperature in an economizer region which may in some circumstances reduce or average out experimental error associated with a temperature measurement at one or more discrete locations and/or improve a time response to the control system.

In some cases, predictive control may be used to improve a control system, e.g. by improving time response of the control system, accuracy or precision of control, and/or reducing oscillations during control. For example, a predictive control scheme that accounts for time delay between a point in time at which measurement of a process variable (such as feedwater temperature, temperature in an economizer region, temperature at or near the tube exit, change in tube length, estimated or measured steam quality, estimated or measured thermal input, pressure, solar input such as DNI, and the like) takes place and a point in time at which an adjustment is made to affect such system parameter used. In a single tube, multi-tube, or multi-pass solar boiler, a predictive control scheme that accounts for time delay within the tube and/or a recirculation system can be used. In the case of the control systems illustrated herein (e.g. in FIGS. 4A-4D and 5A-5C), the time delay experienced by water between entry into the inlet and reaching the position temperature measurement l_(TC) can be accommodated using any suitable predictive control method. For example, a Smith predictor may be used to compensate for time delay. An example of a suitable predictor that can be used in solar boilers is illustrated in FIG. 7. There, a control system 700 comprises an outer control system 702, in which an output 716 from the plant (e.g. temperature, length, estimated steam quality, etc.) from the plant 721 is fed back into an input portion of the controller 714 for qualitative or quantitative comparison with a process set point PR_(set), which is, in turn, used to adjust a valve position 722 or diameter of a flow controlling orifice of a tube to adjust mass flow of water into that tube. The control system 700 also comprises an inner control system 704. For the inner control loop 704, the plant output 717 of the desired process parameter or parameters (e.g. temperature in economizer region, tube length, steam quality) is modeled, and such modeled output value is input into a compensator 708, where the modeled output from box 717 is modified according to a time dependent function to account for any change in the output parameter that occurs during the time delay between an actual measurement of the parameter and a control to affect that parameter. The output from the compensator 708 is then provided as input into controller 718 for the inner control system 704. The compensator can use any appropriate time dependent function; in some instances the effect on the output parameter can be modeled as a first order time dependent effect that varies as e^(−t/τ). For example, if a tube temperature measurement at a location t_(TC) is used as a control variable to feedback to control mass flow input at the k^(th) tube inlet {dot over (m)}_(in,k), then the compensator 708 can use a time dependent compensating factor e^(−(t-τ)/τ) to account for the time delay in the measured mass flow (indicated by control valve position) at the inlet and mass flow at l_(TC), where τ=ρAl_(TC)/{dot over (m)}_(in,k), A represents a cross-section inner dimension of the tube, and ρ represents fluid density in the tube. That is, mass flow of fluid in the pipe at location l_(TC) may be estimated by {dot over (m)}_(in,k)+Be^(−(t-τ)/τ), where B is an appropriate proportionality constant. Accordingly, a steam exit quality estimator may be used to predict steam quality as a function of time x(t):

${x(t)} = {\frac{{\overset{.}{m}}_{steam}(t)}{{\overset{.}{m}}_{in}\left( {t - \tau} \right)}.}$

This instantaneous steam quality estimate may then be used to as input for a predictive controller, e.g. predictive control loop 704 as illustrated in FIG. 7. Predictive control can be used with systems comprising single absorber tubes. multiple parallel-connected absorber tubes, or multi-pass absorber tubes. As stated above, process variable information from one tube may be used as input to a predictive control system for another tube in a multi-tube system or multi-pass absorber system having two or more absorber tubes.

In some variations, information that can be supplied to a control scheme can include changes in a process parameter with time that have been previously modeled, measured, tabulated, or calculated, so that it is possible to provide advance information about that process variable to a control system. Such information can be used as predictive control information, or can be used to correct output from a controller. Such advance information can improve a time response of a control scheme. For example, previously modeled, measured, tabulated, or calculated information about solar input may be supplied to a control system as predictive information. Thus, expected changes in insolation due to diurnal motion of the sun or seasonal variations in insolation can be provided in a lookup table or otherwise to a control system. Similarly, expected changes in feedwater temperature can be provided as information to a control system. In some cases, known or expected shadowing patterns, where the sun moves past one or more structures in a solar array, can be provided as information to a control system. Thus, such information about shadowing patterns that change over time can be used to adjust estimated thermal input that may be used in a predictive manner, e.g. as feedforward control.

In some variations, it may be desired to use a feedforward control system in addition to or in lieu of a feedback control system. For example, it may be desirable to provide feedforward information to a control system regarding changes in insolation, as systematic or non-systematic changes in insolation translate to corresponding changes in thermal input. It may be especially useful to provide feedforward information regarding thermal input due to fluctuations in insolation. Solar input (e.g. DNI) and/or a thermal input estimator or thermal input measurement may also be used in a start-up procedure to provide guidance for rotating reflectors to direct solar radiation to begin warming up a receiver, e.g. to indicate when thermal input is exceeding thermal losses. A thermal input estimator that is coupled to a control system for regulating water mass flow into an absorber tube can protect that absorber tube from overheating or dry out by ensuring mass flow when significant thermal input is present, and can stabilize performance by providing stable operation during transients such as occur during shadowing or cloud cover. In one example, the predicted thermal input may incorporate an estimate of thermal losses based on measured process temperatures and a thermal loss model that can be either analytically or empirically derived.

A thermal estimator for a tube can be used that in steady state depends on the boiling point boundary in that tube, the mass flow of steam produced, and the enthalpy of the steam produced. Energy is balanced in the total volume in a control system such as illustrated in FIG. 2, including a boiler tube, a steam separator, and a recirculation system, so that

${{\overset{.}{m}}_{in} + {\frac{L - \lambda}{L}{\overset{.}{Q}}_{in}} - \left\lbrack {{{\overset{.}{m}}_{steam}h_{g}} + {{\overset{.}{m}}_{recirc}h_{f}}} \right\rbrack - {E_{\frac{stored}{dt}}}} = 0.$

The energy stored in the volume is E_(stored)=μ_(f)m_(water)+μ_(g)m_(steam)+C_(p,steel)m_(steel)T_(steel), where μ_(f)=specific internal energy of water under the operating conditions, m_(water)=mass water, μ_(g)=specific internal energy of steam under the operating conditions, m_(steam)=mass steam, c_(p,steel)=heat capacity of the drum material (e.g. steel), m_(steel)=mass drum, and T_(steel)=drum temperature. The change in stored energy with respect to time is

$\frac{E_{stored}}{t} = {{\frac{{\mu}\; f}{P_{drum}}\frac{P_{drum}}{t}m_{water}} + {\frac{m_{water}}{t}\mu_{f}} + {\frac{{\mu}\; g}{P_{drum}}\frac{P_{drum}}{t}m_{steam}} + {\frac{m_{steam}}{t}\mu_{f}} + {c_{p,{steel}}m_{steel}\frac{T_{sat}}{P_{drum}}{\frac{P_{drum}}{t}.}}}$

Accordingly, the thermal input for a tube of length L can be estimated during steam production with the steam valve open as

${\overset{.}{Q}}_{{in},{est}} = {\frac{L - \lambda}{L}\left\lbrack {{{\overset{.}{m}}_{steam}h_{g}} + {{\overset{.}{m}}_{recirc}h_{f}} - {{\overset{.}{m}}_{in}h_{f}} + {\frac{E_{stored}}{t}.}} \right.}$

At steady state, when operating at constant pressure in the steam drum, the estimated thermal input is

${{\overset{.}{Q}}_{{in},{est}} = {\frac{L}{L - \lambda}{\overset{.}{m}}_{in}h_{fg}}},{{{where}\mspace{14mu} \lambda} = {l_{TC}{\frac{h_{f} - h_{i}}{h_{TC} - h_{in}}.}}}$

During warm-up with the steam valve closed

${\overset{.}{Q}}_{{in},{est}} = {{\frac{L}{L - \lambda}\left\lbrack \frac{E_{stored}}{t} \right\rbrack} = {\frac{L}{L - \lambda}\begin{bmatrix} {{\frac{P_{drum}}{t}\begin{Bmatrix} {{\frac{{\mu}\; f}{P_{drum}}m_{water}} + {\frac{{\mu}\; g}{P_{drum}}m_{steam}} +} \\ {c_{p,{steel}}m_{steel}\frac{T_{sat}}{P_{drum}}} \end{Bmatrix}} +} \\ {{\frac{m_{water}}{t}\mu_{f}} + {\frac{m_{steam}}{t}\mu_{g}}} \end{bmatrix}}}$

Thus, it is possible to estimate thermal input based on the length of the tube and the boiling point boundary and rate of change of pressure in a steam drum, and to use that estimated thermal input in a feedforward control.

An example of a control system incorporating feedforward information regarding thermal input and feedback information regarding a process variable such as temperature in an economizer region, length of a tube, or estimated steam quality is provided in FIG. 8. There, control system 800 comprises a plant 801 that includes one or more solar boiler tubes, and optionally a steam drum or the equivalent and a recirculation system. A measured process variable PR 802 from the plant 801 such as temperature in the economizer region, tube length, or measured or estimated steam quality, pressure, feedwater temperature, temperature at or near the exit, or solar input (e.g. DNI) is provided as input to an operator portion 802 of a controller, where it is qualitatively or quantitatively compared with a set point for that process variable PR_(set). The result of this comparison is used in an appropriate algorithm (e.g. PI, PD or PID) in a main portion of a controller 804 to provide an output signal 805 to eventually control a valve that, in turn, controls mass flow alone or in conjunction with a fixed diameter flow control orifice in to the one or more solar boiler tubes in the plant 801. Before reaching the control valve, the output signal 805 from the feedback controller 804 is provided as input into an operator 806. Feedforward information 807 (which may for example be derived from the estimated thermal input) is used to adjust the control signal being sent to the control valve so that a mass flow {dot over (m)}_(in) results that takes into account the change in thermal input. Although the particular embodiment illustrated in FIG. 8 shows estimated thermal input being provided as feedforward information, other types of information can be used as input in such a feedforward control scheme. For example, thermal input changes that have been modeled, measured, tabulated or calculated (e.g. for expected shadowing as a function of time) can be used as feedforward control. In some variations, information from one tube (e.g. temperature at the exit, or in the economizer region, or change in length) can be used as feedforward information for a control system controlling another tube. In some variations, calculated or modeled thermal losses can be provided as feedforward information.

As stated above, any of the control systems and methods described herein can be used to generate steam of a desired quality, or superheated steam of a desired number of degrees of superheat. FIG. 25 shows an example of a control scheme that can be used in a system where saturated steam is generated in a first solar boiler segment of a solar array, and such saturated steam is fed into a second solar segment that is in series with the first boiler segment, and superheated steam exits the second boiler segment. An example of such a system is illustrated in FIG. 13A. In FIG. 25, the first boiler segment 2510 comprises one or more individual solar boilers 2501, connected in parallel. Although the example illustrated in FIG. 25 shows three individual solar boilers 2501 connected in parallel, any suitable number can be used, e.g. 1, 2, 3, 4, 5, 6, 7, 8, 9, or 10, depending on the balance between the first and second boiler segments. Feedwater is supplied to each infidel boiler through control valves and/or fixed diameter flow control orifices 2502. The combined output of the boilers 2501 is delivered to a separator 2503 such as a steam drum or steam accumulator, where it is held under pressure. Liquid recovered from the separator 2503 can be recirculated, as indicated by line 2513. Steam extracted from the separator 2504 is fed through a control valve and/or fixed diameter flow control orifices 2504 into the second boiler segment 2512. Although the particular example illustrated in FIG. 25 shows only a single solar boiler 2505, the second segment can comprise any suitable number of individual boilers, e.g. 1, 2, 3, 4, or 5 depending on the balance between the first and second segments. Superheated steam can be released from the second segment through control valve 2506 to provide superheated steam as indicated by line 2507. The superheated steam generated in the second boiler segment 2512 has a pressure and a temperature, thus, if output pressure is adjusted using valve 2506, temperature can be downward adjusted by using an attemperating spray. Any of the methods described herein can be used to adjust thermal input to the second segment 2512 to attain the desired superheated steam, e.g. by changing the aiming or focus of one or more reflectors such as described in connection with FIGS. 3A-3D. An output temperature from the second segment can for example be a process control variable in a control scheme that positions one or more reflectors in the second segment. It may or may not be desired to control the steam quality exiting the first segment 2510. In those variations where it is desired to control the steam quality exiting the first segment 2510, any of the methods and control schemes as described herein can be used. The boilers of the first and second segments can comprise single tube absorbers, multi-tube receivers, or multi-pass receivers. In some variations, a mix of single tube absorbers, multi-tube receivers, and multi-pass receivers is used in a single system. In other variations, second segment 2512 may be a tower, linear solar (trough or CLFR), or an external heat source such as a coal fired or natural gas fired burner.

In some variations, it may be desired to use a staged control scheme, where one control scheme is used until the boiler reaches a certain predetermined status, and then a second control scheme is activated. Such a scenario can occur, for example, in the instance where superheated steam is being generated in a once through configuration, e.g. as illustrated in FIG. 2 and FIG. 14. An example of a staged control scheme is provided in FIG. 26. There, control scheme 2600 comprises a first control system 2610 and a second control system 2612. The first control system 2610 is operational when the plant is producing saturated steam. The first control system 2610 comprises a plant 2611 that comprises one or more boiler tubes, and optionally a separator and a recirculation system as described herein. A process control parameter 2614 PR_(sat) as described herein is provided to an operator portion 2630 of a controller. The measured value PR_(sat) is quantitatively or qualitatively compared with the set value for that parameter PR_(set,sat). The operator portion 2630 feeds the results of that comparison to a main portion of a controller 2631, which provides as output a proportionality constant α_(sat) which determines a mass flow per tube as described above in connection with FIG. 4C, and is then fed into a converter function 2633 for controlling a position of a valve to control mass flow into that tube alone or in conjunction with a fixed diameter flow controlling orifice. In this particular example, the second control system 2612 is identical in all respects, except for the process control variable that is used. A process variable from the output of the plant PR_(exit) 2618 is used to detect whether or not the system is close to producing superheated steam, e.g. temperature at or near the exit of the tube, estimated or measured steam quality, tube length, or pressure. A value of the output process variable PR_(exit) is compared to a set point for that variable PR_(set,exit). A comparison between the output process variable and the set point for that variable and a determination of whether or not a threshold value for that parameter PR_(SH) has been exceeded or not determines which control system is operational. Thus, if PR_(set,exit)−PR_(exit)>PR_(SH), then the control scheme uses the first control system, and hence the values α_(sat) to control valve positions. For example, if the output process control variable is temperature, then if the temperature at the exit of the tube is low relative to a threshold (e.g. about 10 degrees, or about 20 degrees below) then a control scheme for saturated steam is used, whereas if the temperature at the exit of the tube is close to a point at which superheat will be made (e.g. within about 10 degrees or about 20 degrees of a set point), then a control system for superheated steam can be used. In one example of a control system for superheated steam, a temperature at or near the exit of the tube is used as a process control variable to supply to a controller, e.g. as shown in FIG. 26.

Any one of the control systems (e.g. feedback or feedforward control systems) described herein may comprise a clip function, so that any control signal sent to a control valve will not cause a control valve position to be adjusted below a certain minimum setting and or above a certain maximum setting. In some variations, a valve position may be provided as an input to a feedback control system that controls operation of a recirculation pump, e.g. a variable frequency drive for a recirculation pump. For example, if one or more control valves is almost closed so that mass flow is very low, a controller can reduce the pump frequency to avoid a low flow trip condition in the plant. An example of such a control system is illustrated in FIG. 24. There, a system 2400 comprises a solar thermal plant 2401 that comprises a single absorber tube, multiple absorber tubes in parallel (multiple parallel-connected tubes within a receiver or multiple single tube or multi-tube lines connected in parallel), or one or more multi-pass absorber tubes, a steam separator such as a steam drum, a recirculation system for recirculating recovered water from the separator, and a feedwater input. Mass flow into one or more of the absorber tubes is regulated using a control valve or manifold of k control valves CV_(k) and/or fixed diameter flow controlling orifices as described herein. Control valve position 2402 is provided as input to a controller 2403 (e.g. in a feedback loop). A valve position is qualitatively or quantitatively compared with a valve position set point CV_(set) (e.g. a maximum value for closing a valve is 60% closed by mass or by volume). If a maximum valve position for any one of k control valves in the system exceeds the set point, then the frequency that the recirculation pump is running at can be reduced. For example, the operation frequency of a variable frequency drive for the pump can be reduced by a factor

$1 - \frac{{trip\_ m}\mspace{14mu} \arg \mspace{20mu} {in}}{{min\_ m}\mspace{14mu} \arg {\mspace{14mu} \;}{in}}$

where min_margin is an empirically determined number such as about 0.1 kg/sec, 0.2 kg/sec or 0.3 kg/sec, and trip_margin represents the lowest mass flow value that will cause a low flow trip in the system. A clipping function can be included in such a control system so that the pump frequency does not drop below a minimum frequency. Such a control system for adjusting recirculation pump frequency can be used in conjunction with any one of the control systems for controlling mass flow and/or thermal input into one or more absorber tubes as described herein.

As stated above, the systems and methods described herein for controlling steam quality may be adapted to single tube solar thermal systems, such as a single line, single tube LFR system or a single line of parabolic trough sections, solar thermal systems that include multiple parallel-connected absorber tubes, such as a multi-line single tube LFR system, a single line multi-tube LFR system, a multi-line multi-tube LFR system, or a multi-line parabolic trough system, or multi-pass solar thermal systems having one or more multi-pass absorber tubes. Further, it may be desirable to provide individual process variable input for each tube to a controller, or it may be desirable to combine process variable input from multiple tubes to provide an aggregated input to a controller. FIG. 9A illustrates an example of a solar thermal steam generator in which m tubes 901(1) . . . 901(m) (m>1) are arranged in parallel. In this particular example, process variable input (e.g. temperature within an economizer section, length of a tube section, or steam quality estimate) from each of the m tubes can be used to provide an individual set point PR_(set,1) . . . PR_(set,m) for each of the m tubes to a controller 904 capable of controlling m channels individually, or to multiple controllers. Alternatively, an aggregate set point PRset can be used for each of the m tubes. FIG. 9B illustrates an example of a solar thermal steam generator comprising m multi-tube receivers (m>1), each receiver comprising k tubes, so that each tube 950(1,1) . . . 950(k,m) within the system can be individually controlled, or controlled as part of an aggregate group. For example, all k tubes within a receiver may be controlled as part of an aggregate group, but each of the m receivers may be controlled separately from one another.

In some variations, it may be desired to control both mass flow and thermal input into one or more tubes. Referring back to FIGS. 3A-3D, thermal input may be varied transversely (e.g. across multiple tubes) while being maintained as relatively constant longitudinal, thermal input may be varied longitudinally while being maintained as relatively constant transversely, or thermal input may be varied both transversely and longitudinally. Longitudinal thermal input may be varied, for example, by selectively rotating a segment of an elongated reflector in an LFR array, or by selectively rotating a section of a row of end-to-end coupled parabolic troughs, as illustrated FIG. 3D. Other methods for varying thermal input along a length of a tube include selectively shading a segment of a receiver, or selectively shading a segment of an elongated reflector. Transverse adjustment of thermal input while maintaining a relatively constant longitudinal thermal input can be achieved by rotating an entire length of an elongated reflector as illustrated in FIGS. 3B-3C. It may, for example, be desired to reduce thermal input to a tube if a position of a control valve that controls mass flow to that tube is near a limit such that mass flow cannot be increased, if a control valve position indicates that mass flow is below a minimum level, or if a temperature measurement indicates that overheating in a tube is occurring.

Examples of drive systems for rotating reflector rows or segments of reflector rows are provided in FIGS. 21-23. FIG. 21 illustrates a configuration in which the angle of a row of linearly coupled reflectors is controlled by a drive located at a single terminus of the row. Although FIG. 21 illustrates the reflectors each turning the same direction, it is understood that each row of reflectors can be individually activated or not, and when activated, may move in a clockwise or counterclockwise direction. In this configuration, if the angle at which a row of reflectors is changed by moving the reflectors via the drive form a first to a second position, the reflectors in the row that are distant from the location of the drive may experience lag.

FIG. 22 illustrates an alternative configuration, in which any lag that may be experienced with the configuration of FIG. 21 is reduced by placement of the drive at a more central position along the row of the linearly positioned reflectors. In this way, when the drive is activated to modify the angle at which the reflectors are positioned, there is less distance between the drive and any one portion of the rows of reflectors as compared to the configuration of FIG. 21.

FIG. 23 illustrates a further alternative configuration, in which single reflectors are individually controlled by a drive, as compared to the linearly conjoined row of reflectors of FIGS. 21 and 22. In the configuration of FIG. 23, lag is reduced because each reflector is individually controlled by a separate drive. Similar embodiments are envisioned in which small groups of reflectors within a row are controlled by a separate drive, where the length of the group is limited so as to reduce lag to an acceptable level. Each reflector drive may turn its reflector clockwise or counterclockwise or remain in a set position. As illustrated in the figure to the right, the reflectors may also contain a supporting beam coupled to the drive and extending linearly along the underside of the reflector to assist with uniform rotation along the length of the reflector. Supporting beams may also be used in other reflector configurations, such as those in FIGS. 21 and 22, e.g. to reduce lag.

In one variation, a control system for controlling reflector position activates a drive causing reflector movements in an amount of about 1 to about 5 degrees or about 1 to about 10 degrees or about 5 to about 15 degrees in a clockwise direction to a set point, followed by reverse movement of the same amount in the counterclockwise direction. The control system continues to oscillate the reflectors by causing incremental reflector movements in a first and then in an opposite direction at a desired frequency for a period of time, e.g. at a frequency in a range from about 0.01 Hz to about 50 Hz, e.g. about 0.1 Hz, about 1 Hz, or about 10 Hz.

In some variations, it may be desired to provide a warm start up for a solar boiler. In one variation, a warm start up for a solar boiler can be accomplished by providing steam from an auxiliary source into an exit of a boiler tube. Any suitable auxiliary steam source can be used, e.g. from a steam accumulator, a coal-fired or natural gas-fired steam source, or from another solar boiler. In some variation, steam can be taken from a steam accumulator for the solar boiler being started up. In FIG. 10B, a temperature profile as a function of length along a boiler tube of a cold system 1050 is shown, along with a desired operating temperature profile 1052. By providing steam input into an exit end of the boiler tube, the temperature profile in the tube can be gradually built up (as indicated by curves 1053) to be similar to that of the desired profile 1052. After the tube is warmed up in this manner, water can be flowed into the inlet at a low flow, and thermal input can be supplied by rotating reflectors. After steam is observed exiting the tube, then full operation can begin by increasing water flow and increasing thermal input.

A control system that controls both mass flow into one or more tubes and reflector position may be used to adjust start up conditions in a solar receiver. It may be desirable to adjust start up conditions so that initial boiling occurs near the exit of the tube, and then the boiling point moves along the pipe toward the inlet as warm up progresses. By controlling startup conditions so that initial boiling occurs near the exit of the tube, scenarios can be avoided in which boiling occurs in an interior region of the tube removed from the exit, so that the boiling displaces water beyond the boiling point which is dumped into a recirculation system, causing water level overflow. In a solar receiver, some reservoir of warm water may exist from previous day's operation. As illustrated in FIG. 10A, an example of a solar boiler system 1000 that includes a boiler section 1004 comprising one or more tubes and a recirculation section 1002 is illustrated. During operation, heat is directed to the boiler section 1004 using one or more reflectors (e.g. linear Fresnel reflectors or parabolic trough reflectors). Water is fed into the boiler section at the inlet through control valve manifold 1014 (which may contain one control valve and/or fixed diameter flow controlling orifice for all tubes, one control valve and/or fixed diameter flow controlling orifice for each tube, or multiple control valves and/or fixed diameter flow controlling orifices, where each control valve and/or fixed diameter flow controlling orifice controls mass flow into multiple tubes, as described above). Boiling occurs at some position λ, along the tube, so that steam exits the boiler section 1004. Output from the boiler section 1004 enters a steam drum or equivalent 1006, where steam is extracted, e.g. through valve 1040. During operation, a liquid level in the drum 1006 can be correlated to a boiling point λ, in a tube, taking into account a flow rate in that tube. After a period of nonoperation (e.g. shutdown or darkness), the boiler section 1004 contains relatively cold water. The recirculation section, including the steam drum 1006 contains fluid at a temperature T_(recirc) and pressure P_(drum). A valve 1008 can be installed between the recirculation system 1002 and the boiler section 1004. The valve or valves CV_(k) at the boiler inlet and the valve 1008 at the boiler exit can be closed so as to isolate the boiler section from the recirculation section during periods of nonoperation. Pressure in the boiler section drops as temperature drops; optionally, cold water can be drained from the boiler section using valve 1010 during nonoperation, e.g. using a dump condenser 1020. At startup, the valve 1008 can be opened so that relatively warm water is sucked back into the colder, lower pressure boiler section, which reduces the liquid level in the drum 1006. After pressure equalization between the boiler section 1004 and the recirculation section 1002, one or more control valves CV_(k) 1014 and recirculation valve 1012 can be opened so that fluid begins to flow through all of the tubes (one tube for a single tube receiver or multiple tubes) in the boiler section 1004. After water begins to flow through the receiver, heat can be preferentially applied to an end section 1015 of the boiler section. The end section 1015 may be any suitable section of the boiler adjacent the exit, but in some variations, the end section may be about ¼ or about ⅓ the length of the tube that is adjacent the exit. Preferential heating can occur in a LFR solar array by tuning only a section of reflectors in a line of reflectors to selectively illuminate the end section, while the other reflectors in the line are inverted or otherwise arranged so as to not direct solar radiation to the boiler section. Preferential heating of an end section in a parabolic trough array can occur by orienting only those parabolic trough sections near the end of a line so as to receive solar radiation, whereas other sections of a line of parabolic troughs remain inverted or otherwise dark to the sun. As selective heating begins near the end 1015 of the boiler, the liquid swell level in the drum 1006 increases. Monitoring the liquid swell level in the drum 1006, along with mass flow rate into the boiler section 1004 (indicated by control valve position) can provide an indication of the position of the boiling point λ. After the initial boiling point is established near the end of the boiler section by selective irradiation of the end of the boiler section, the boiling point can be systematically moved to a desired upstream position by systematic increase of mass flow of water with control valve manifold 1014 and systematic increase of heat flux to the boiler by directing solar radiation to regions of the boiler upstream relative to the end section 1015, while monitoring level swell in drum 1006.

As stated above, saturated steam or superheated steam produced using the systems and methods described herein may be used to drive a turbine to generate electric power. Referring now to FIG. 11, steam generated by a steam generator 1 which may comprise any steam generator configuration described herein, including those employing multi-tube receivers, those employing multi-pass receivers, and those employing single tube receivers, is delivered to a turbine 2, which drives an electric generator 3. The turbine 2 is driven by dry steam, so steam generated by steam generator 1 can be dry by virtue of being superheated steam, or saturated steam can be passed through a separator (not shown). FIG. 12 illustrates another embodiment of an electric power plant in which a steam generator 1 as described in FIG. 11 produces dry steam to drive a turbine 2 that, in turn, drives an electric generator 3. Condensate from the turbine 2 can be captured in condenser 5, and stored in a reservoir 6. Pumps 7 can circulate the condensate to provide water input to the steam generator 1. In some variations, a thermal energy storage system 4 is utilized to store thermal energy generated by the steam generator so that such stored thermal energy can be tapped at a later time and used to drive turbine 2.

It is understood that the systems and methods described herein can be used in conjunction with a variety of solar thermal plants, including a variety of LFR solar arrays. For example, and with reference to FIG. 13A, a LFR system 1300 comprises a first LFR stage 1301 in series with a second LFR stage 1302. The first LFR stage comprises a field of linear Fresnel reflectors 1304 arranged in use to track diurnal motion of the sun and to direct reflected solar radiation to one or more elevated receivers 1305. An elevated receiver 1305 may comprise a single absorber tube, a plurality of parallel-connected absorber tubes, or one or more multi-pass absorber tubes. Saturated steam is generated in the first LFR stage. The saturated steam output from the first stage is passed through a separator 1306 (e.g. a steam drum, a steam accumulator, one or more baffles, or a cyclone separator). Water collected in the separator is circulated back to the inlet of the first stage. Steam collected from the separator is provided as input into the input of an elevated receiver 1307 in the second LFR stage 1302. A field of linear Fresnel reflectors 1307 direct reflected solar radiation to the elevated receiver 1309 to generate superheated steam in the second stage. The elevated receiver 1309 can comprise a single absorber tube, multiple absorber tubes, or one or more multi-pass absorber tubes. The superheated steam can optionally be passed through a separator 1308 to generate a higher quality of steam. In some variations, the second LFR stage can be replaced in whole or in part by an external heat source such as a coal fired or natural gas fired burner. It may be possible to bypass the second stage if superheated steam is not desired as indicated in the figure by line 1310. After the superheated steam is used (e.g. to drive a turbine 1311 to generate electric power), the turbine exhaust may be sent to a condenser (not shown), from which condensate may be collected and fed back into the first stage. As the second stage is configured for generating superheated steam, a different number, different diameter, or different composition of tubes may be used in the second stage as compared to the first stage. The second LFR system may have fewer, larger diameter tubes that may also be shorter in length, if desired, than tubes of the first LFR stage. A ratio of the diameter of the tubes in the second LFR stage generating superheated steam to the diameter of tubes in the first LFR stage may be greater than one, e.g. the ratio may be at least 1.5, at least 2, at least 3, at least 4, at least 5, or even larger, e.g. about 10. If the first stage LFR system utilizes 10 parallel-connected 2-inch diameter carbon steel absorber tubes, the second stage LFR system may utilize 5 4-inch diameter absorber tubes. Any one of or any combination of the control systems and methods described herein can be used with the first LFR stage and/or the second LFR stage.

FIG. 13B illustrates a multi-pass configuration of LFR system 1300 shown in FIG. 13A. In particular, LFR system 1320 of FIG. 13B comprises a first multi-pass LFR stage 1321 in series with a second multi-pass LFR stage 1324. First multi-pass LFR stage 1321 may comprise one or more multi-pass absorber tubes 1322. Saturated steam is generated in the first multi-pass LFR stage 1321 and output through a separator 1326 (e.g. a steam drum, a steam accumulator, one or more baffles, or a cyclone separator). Water collected in the separator is circulated back to the inlet of the first stage using circulation pump 1327. A blowdown valve 1330 may be included to allow for draining and/or purging of contaminates (e.g., particulates, scum, and the like) from the system. Steam collected from the separator is provided as input to second multi-pass LFR stage 1324. Additionally, feed-water may be input into second multi-pass LFR stage 1324 at 1328. Second multi-pass LFR stage 1324 may comprise one or more multi-pass absorber tubes 1325. In some variations, the second multi-pass LFR stage 1324 may be replaced in whole or in part by an external heat source such as a coal fired or natural gas fired burner. Second LFR stage 1324 may output superheated steam at 1329 and provide heated water to circulation pump 1327 to be fed back into first multi-pass LFR stage 1321. The superheated steam can optionally be passed through a separator to generate a higher quality of steam. As the second stage is configured for generating superheated steam, a different number, different diameter, or different composition of tubes may be used in the second stage as compared to the first stage. The second multi-pass LFR system may have fewer, larger diameter tubes that may also be shorter in length, if desired, than tubes of the first LFR stage. It may be possible to bypass the second stage if superheated steam is not desired. Any one of or any combination of the control systems and methods described herein can be used with the first multi-pass LFR stage and/or the second multi-pass LFR stage.

With reference to FIG. 14, an LFR system is detailed in which superheated steam is generated in a single stage LFR receiver. In such a configuration, as detailed here and elsewhere throughout, the absorber tube or tubes or at least the portion carrying superheated steam, will be configured for use with superheated steam. As illustrated in FIG. 14, system 1400 comprises a field 1401 of linear Fresnel reflectors directing solar radiation to an elevated receiver 1402, and each row of reflectors rotating about a single axis to track diurnal motion of the sun. In one variation, the elevated receiver 1402 comprises multiple parallel-connected absorber tubes, and each absorber tube is of sufficient length, and receives sufficient thermal input to generate superheated steam therein at a desired temperature and pressure. In another variation, the elevated receiver 1402 comprises one or more multi-pass absorber tubes, and each absorber tube is of sufficient length, and receives sufficient thermal input to generate superheated steam therein at a desired temperature and pressure. Superheated steam from the receiver 1402 can be used directly as process steam, or can be used to drive a turbine 1403 to generate electric power. In one such variation, the portion of the absorber tubes near the inlet may be of a different number, different diameter, different composition, different type, and/or different wall thickness than those at the more distant end from the inlet, where the temperature and pressure are that required to produce superheated steam. A skilled artisan would recognize that adapters or other piping configurations may be assembled as transition section between differing absorber tubes. Any one of or any combination of the control systems and methods described herein can be used with a single stage superheated steam generator, e.g. as illustrated and described in connection with FIG. 14.

Any of the control systems described herein may employ additional sensors. For example, multiple temperature sensors may be positioned at spaced apart locations along a length of an absorber tube. One or more flow rate sensors may be used to measure flow rate of liquid and/or vapor within an absorber tube. One or more pressure sensors may be used to monitor pressure along the length of a tube, in a steam drum or accumulator, or in a recirculation system.

In some situations, it may be desirable to measure temperature, pressure, or flow rate differences between adjacent ones of absorber tubes in a multi-tube receiver, adjacent ones of absorber tubes in a multi-pass receiver having two or more absorber tubes, or adjacent ones of segments in a multi-pass receiver. For example, it may be desired to position temperature sensors at the same or approximately the same location along multiple tubes in a multi-tube receiver or multi-pass receiver having two or more absorber tubes or along multiple segments in a multi-pass receiver to map out a temperature profile transversely and longitudinally. Various arrangements of sensors in a multi-tube receiver are provided in FIGS. 15A-15D. With reference to FIG. 15A, each absorber tube 1501 contains sensors 1502 positioned at both termini of each absorber tube and at approximately equal distances throughout the length of the absorber tube. As such, a measurement of temperature, flow rate, and/or pressure may be taken at the inlet and outlet and throughout the length of the receiver. In FIG. 15B, an arrangement is provided which is similar to that in FIG. 15A, except that no sensors at the absorber tube termini are included. In FIG. 15C, a configuration is provided in which adjacent pairs of absorber tubes have sensors at approximately the same longitudinal positions. In FIG. 15D, a configuration is provided in which the innermost absorber tubes in the receiver, which may be susceptible to receiving more reflected incident solar radiation than those positioned at the outer edges of the receiver, are fitted with more sensors than the outer absorber tubes. While FIGS. 15A-15D illustrate the placement of contact sensors on multi-tube receivers, one of ordinary skill will appreciate that principals described with respect to FIGS. 15A-15D may similarly be applied to absorber tubes of a multi-pass receiver.

As stated above, any of the control systems described herein can be employed in conjunction with a LFR system employing one or more multi-tube receivers or multi-pass receivers. A reflector field that may be employed includes the LFR array described in U.S. patent application Ser. No. 10/597,966 entitled “Multi-tube solar collector structure,” filed Feb. 17, 2005 and U.S. patent application Ser. No. 12/012,829 entitled “Linear Fresnel Solar Arrays and Receivers Therefor,” filed Feb. 5, 2008, each of which is incorporated by reference herein in its entirety, specifically with respect to the LFR reflector fields detailed therein. For example, referring now to FIGS. 16-17, a linear Fresnel reflector 1600 may comprise a space frame 1601 to which multiple mirror panels 1602 are adhered. The mirrors may be flat, or may have a parabolic cross-section. In some variations, multiple support hoops 1603 connect to the space frame and engage mounted wheels that allow the hoops and therefore the reflector to rotate about a longitudinal axis parallel to an elevated receiver 1604. In other variations, other types of rotatable supports are used to rotate and position a reflector, e.g. supports that do not extend substantially above the reflective surface of the mirror, such as those described in U.S. Pat. No. 5,899,199 to Mills, which is incorporated by reference herein in its entirety. A reflector may be rotated and positioned using a single motor and drive that drives one or more of the reflector supports, e.g. hoops. For example, a single motor and drive may rotate and position a group of ganged together reflectors, e.g. as described and illustrated in connection with FIGS. 21-23. In some variations, a relatively horizontal reflector may be positioned directly beneath the receiver 1604 to provide an image on the receiver that is parallel to the reflector and has relative constant transverse illuminance across the receiver. FIG. 18 illustrates an example of positioning of reflectors in an LFR array to illuminate a receiver distant from the receiver closest to the LFR array.

Examples of multi-tube receivers that may be used in an LFR array are described in U.S. patent application Ser. No. 10/597,966 entitled “Multi-tube Solar Collector Structure,” and filed Feb. 17, 2005 and in U.S. patent application Ser. No. 12/012,829 entitled “Linear Fresnel Solar Arrays and Receivers Therefor,” and filed Feb. 5, 2008, each of which is incorporated by reference herein in its entirety.

Another example of a receiver that can be used, e.g. for generating superheated steam, is provided in FIG. 20. There, receiver 2000 comprises 5 tubes 2001 parallel to one another along the length of the receiver. The tubes may, for example, have a 4″ diameter. Other variations are contemplated in which 10 parallel tubes are used in a receiver, where each tube has a 2″ diameter or a 1.5″ diameter. In the example illustrated in FIG. 20, the tubes 2001 are supported by a series of rollers 2002, spaced apart along the length of the tubes. Other variations are contemplated in which a single roller 2002 is replaced with a set of coaxial, independently rotating rollers, where each roller in the set supports a single tube to accommodate differential thermal expansion of the multiple tubes. The tubes 2001 are housed in a trapezoidal cavity 2003, with the bottom surface of the cavity provided by a window 2006 selected to transmit solar radiation. The trapezoidal cavity, tubes, and rollers 2002 are supported by a frame 2004. A protective roofing 2005 is provided over the frame.

The tubes in the receiver undergo thermal expansion that must be accommodated. Rollers on which the tubes reside may allow the tubes to expand and contract without damaging a coating on the tubes. Rollers may assume a contoured shape, a “V” shape, or a “U” shape to help guide individual tubes along a linear path and avoid unwanted lateral deflection that might cause adjacent tubes to damage each other. Tubes may be clamped e.g. to the receiver housing or to another fixed support structure at or near the tubes' midpoints, while ends of the tube remain free to move. This configuration allows both ends of the tubes to move and limits the extent of thermal expansion to half that which would have to be accommodated if an end of a tube was anchored.

Piping connecting to ends of tubes, and downcomer piping sections that transport steam from the receiver to ground level may be designed to accommodate thermal expansion. For example, as illustrated in FIG. 19, tubes 1900 may be connected to a piping section 1902 that comprises one or more hairpin thermal expansion sections 1901. The curved portions of the hairpin section may increase and decrease in radius as needed to accommodate the linear expansion and contraction of the tubes 1900. The hairpin may have one large curved region generally shaped in the form of a question mark, or the hairpin may comprise multiple curved sections and one or more straight sections. Movement of one or more portions of piping (e.g. as illustrated in FIG. 19) can be used to determine a change in length, which can be, in turn, used as a process control variable for any of the control schemes described herein.

Using any of the control systems and methods described herein, the steam quality may be controlled to any desired quality, e.g. about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8 or about 0.9. In some cases, superheated steam may be produced. The steam quality within an individual tube may be controlled to +/−about 20%, about 15%, about 10%, about 5%, or even better, e.g. about 2%. The steam quality for a multi-tube receiver may be controlled to about +/−20%, about 15%, about 10%, about 5%, or even better, e.g. about 2%. For example, in some systems steam may be controlled within the individual tubes to a desired steam quality (e.g. 70%) within +/−10% in operation, and to within about +/−5% for an overall multi-tube receiver, e.g. a multi-tube receiver comprising 10 parallel 1.5 inch diameter carbon steel tubes.

Superheated steam may be produced by variations of systems and methods described herein at a temperature of at least about 370° C., at least about 371° C., at least about 372° C., at least about 373° C., at least about 374° C., at least about 375° C., at least about 380° C., or about 390° C. or higher, or a temperature in a range from about 370° C. to about 380° C., or about 370° C. to about 390° C., or about 370° C. to about 400° C. In some variations, superheated steam may be produced at somewhat lower temperatures, e.g. in a range from about 350° C. to about 370° C., or in a range from about 350° C. to about 360° C., or in a range from about 360° C. to about 370° C. such as about 369° C. or lower, or about 365° C. or lower. In yet other variations, superheated steam may be produced up to temperatures of about 580° C. While specific temperature ranges are described, it should be appreciated that steam having any temperature may be produced depending on the desired application. 

1. A method for producing steam, the method comprising: flowing water through an inlet to enter a tube of length L under pressure; irradiating the tube along its length with solar radiation so that solar radiation absorbed at the tube generates thermal input to the tube along its length and so that steam exits the tube; and providing a control variable as input to a controller that controls mass flow of water through the inlet, thereby controlling quality of steam exiting the tube.
 2. The method of claim 1, wherein the control variable comprises a change in tube length.
 3. The method of claim 1, wherein the control variable comprises a temperature in an economizer region of the tube.
 4. The method of claim 3, wherein a temperature setpoint of the control system depends on the position of the temperature measurement relative to the tube inlet, tube length L, and a desired output steam quality.
 5. The method of claim 1, wherein: the tube has a transverse dimension W orthogonal to length L; irradiating the tube comprises rotating a reflector to direct solar radiation to irradiate the tube along its length L; and the method further comprises adjusting a thermal input to the tube by rotating a position of the reflector to control the quality of steam exiting the tube.
 6. The method of claim 1, wherein the control variable comprises predictive information associated with thermal input.
 7. The method of claim 6, further comprising separating water that exits the tube from the steam using a separator, and wherein the predictive information comprises thermal input that is based on steam flow out of the separator.
 8. The method of claim 7, wherein the separator comprises a steam drum.
 9. The method of claim 1, wherein the desired steam quality is 70% or higher.
 10. The method of claim 1, adapted for producing superheated steam.
 11. A method for producing steam, the method comprising: flowing water into an inlet of a solar receiver in a linear Fresnel reflector system, wherein the receiver comprises multiple tubes connected in parallel; irradiating each tube along its respective length with solar radiation so that solar radiation absorbed by each tube generates thermal input along its length and so that steam exits the tube; and using one or more control variables associated with one or more tubes as input to a controller that controls mass flow of water into each of the multiple tubes, thereby controlling steam quality exiting the receiver.
 12. The method of claim 11, wherein the one or more control variables comprise one or more temperatures measured in an economizer region of the one or more tubes.
 13. The method of claim 11, wherein the one or more control variables comprise a change in tube length of the one or more tubes.
 14. The method of claim 11, wherein the one or more control variables comprise predictive information associated with thermal input.
 15. The method of claim 11, wherein: the receiver has a length L and a transverse dimension W orthogonal to L; irradiating each tube along its respective length with solar radiation comprises rotating one or more rows of linear Fresnel reflectors in a field of reflectors about an axis to direct solar radiation to irradiate the tubes along length L; and the method further comprises adjusting thermal input to the multiple parallel tubes along the transverse dimension W by rotating one or more of the reflector rows about the axis to control the steam quality.
 16. A solar boiler comprising: a tube having an inlet for receiving water and an outlet; a control valve capable of regulating flow of water into the inlet; and a controller for controlling a position of the control valve to control flow of water into the inlet based at least in part on a control variable to control a steam quality at the outlet.
 17. The solar boiler of claim 16, wherein the control variable comprises a temperature in an economizer region of the tube.
 18. The solar boiler of claim 16, wherein the control variable comprises predictive information associated with thermal input.
 19. The solar boiler of claim 16, wherein: the tube is anchored at a position P between the inlet and the outlet, the position P extending further from the inlet than a boiling boundary in the tube; the tube is relatively free to expand at the inlet; and the control variable comprises a measurement of a change in length of the tube between the inlet and position P.
 20. A solar boiler comprising: an elevated receiver comprising multiple parallel tubes extending along the length of the receiver; a plurality of linear Fresnel reflectors configured to rotate about an axis to track diurnal motion of the sun; a control valve associated with each of the tubes to regulate mass flow of water into the tubes; and a controller for adjusting a position of the control valve associated with each tube based at least in part on one or more control variables associated with one or more tubes so as to control mass flow of water into each tube and to control steam quality output from the receiver.
 21. The solar boiler of claim 20, further comprising one or more temperature sensors positioned to sense fluid temperature in the economizer region of the one or more tubes, wherein the one or more control variables comprise output from the one or more temperature sensors.
 22. The solar boiler of claim 20, wherein the one or more control variables comprise predictive information associated with thermal input.
 23. The solar boiler of claim 20, wherein the one or more control variables comprise a change in length of the one or more tubes. 